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Transcript of 1 New Generation Strategy IGCC Technology New Generation Strategy IGCC Technology Presented by: Mary...
1
New Generation Strategy
IGCC Technology
New Generation Strategy
IGCC TechnologyPresented by:
Mary Zando, Manager
Chemical Systems,
New Generation Projects
Dan Duellman, Manager
Mechanical & Balance of Plant,
New Generation Projects
Monty Jasper, Manager
New Plant Development Projects
APP Site Visit
October 30 – November 4, 2006
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Revenues: $14.5 billion
Assets: $37 billion
US customers: 5 million
US employees: 22,000
Source: AEP 2003 Annual Report
The American Electric Power System
100 years in operation
36,000 MW generation capacity – more than 70% coal Largest generator of electricity in US Largest coal purchaser and consumer – over 70 million
short tons (64 million metric tons) per year
39,000 miles (62,000 km) transmission 7,900 miles (12,600 km) 230 – 765 kV
200,000 miles (320,000 km) distribution 5 million customers in
11 states
$11.9 billion annual revenue $36.2 billion assets
Source: AEP 2005 Annual Report
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The American Electric Power System
4
Revenues: $14.5 billion
Assets: $37 billion
US customers: 5 million
US employees: 22,000
Source: AEP 2003 Annual Report
AEP Today: The Need for New Generation
AEP is committed to providing reliable, affordable, and sustainable electricity to our 5 million customers.
AEP has not added base load capacity since 1991 (Zimmer conversion)
AEP will need approximately 1200 MW of additional generating capacity in our Eastern region by 2010
AEP believes that Integrated Gasification Combined Cycle (IGCC) technology is the best choice for capacity additions in the East
Lansing
Indianapolis
FrankfortAshland
Charleston
Ft.Wayne
South Bend
Wheeling
Indiana
Ohio
Michigan
Kentucky
Tennessee
Columbus
Richmond
VirginiaWest
Virginia
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Site Selection & Evaluation Process
Where is the best site to build a new IGCC Power Plant in AEP East? Site Study Team Established
Representatives from AEP Third Party Consultant retained for study
Potential Sites Identified AEP existing plants sites AEP owned/controlled property Fatal Flaw Analysis to narrow list 15 sites identified for evaluation
Developed Ranking Criteria Established Design Basis
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Design Basis - Key Siting Parameters
600 MW IGCC Unit (with option to expand to 1200 MW) 2 x 2 x 2 x 1 Configuration
2 Operating Gasifiers / Gas Cleanup Systems 2 Combustion Turbines 2 Heat Recovery Steam Generators 1 Steam Turbine
600 MW 1200 MW
Fuel Consumption 2 million(1.8 million)
4 million(3.6 million)
short tons per year(metric tons per year)
Heat Rate HHV 8,500 (2,142) 8,500 (2,142) Btu/kWh (kcal/kWh)
Make-up water flow 5,500 (347) 11,000 (693) gallons per minute (liters per second)
Land Requirements:
power block 30 (12) 45 (18) acres (hectares)
gasification island 60 (24) 105 (43) acres (hectares)
rail loop 150 (60) 150 (60) acres (hectares)
coal yard 40 (16) 40 (16) acres (hectares) inside rail loop
solid waste disposal 150 (60) 300 (121) acres (hectares)
Total (rail delivery) 390 (158) 600 (243) acres (hectares)
Total (barge delivery) 280 (113) 490 (198) acres (hectares)
Operating staff 125 200 full time equivalent employees
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Site Selection Ranking Criteria
Site Topography Topography and Size Expandability Distance from Waste Disposal Flood Potential Constructability
Air & Water – Environmental Distance from Class I Areas Dispersion Conditions Existing Air Quality Air Quality Non-Attainment Area CO2 Sequestration - Third Party
Desktop Study Transmission
Distance from Transmission Transmission Stability Feasibility of 2 Unit Transmission
plan
Fuel Delivery Distance from Rail or Barge Alternate Transportation Distance from Natural Gas Pipeline Delivered Coal Cost Differential
Cooling Water Distance from Adequate Water Source Adequacy of Cooling Water Source
Land Use Designated Parks & Recreation Areas Existing Land Use Existing Residences Nearby Land Use
Habitat Wetlands Impact Potential Other Natural Habitats Impact Potential Documented Presence of Threatened
and Endangered Species
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Site Selection Ranking Criteria
Weighting Factors Scale of 1 - 10
Rating Factors Scale of 1 – 5
Example below
Criteria Description Weighting Factor
Evaluation Criteria Rating Factor
Plant Site Topography and Size 8 0.5 to 1.0 percent slope and less than 100,000 c.y. (76,000 cubic meters) fill
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1.0 to 2.0 percent slope or 100,000 to 300,000 c.y. (76,000 to 228,000 cubic meters) fill
4
2.0 to 3.0 percent slope or 300,000 to 600,000 c.y. (228,000 to 456,000 cubic meters) fill
3
3.0 to 4.0 percent slope or 600,000 to 1,000,000 c.y. (456,000 to 760,000 cubic meters) fill
2
4.0 to 5.0 percent slope or more than 1,000,000 c.y. (760,000 cubic meters) fill
1
Expandability for Future Units 7 Three or more units can fit on site 5
Only two units can fit on site 3
Only one unit can fit on site 1
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Results
Top Sites by State Mountaineer – West Virginia Great Bend – Ohio Carrs - Kentucky
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Generating Technology Options: Integrated Gasification Combined Cycle (IGCC) Plants
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Business Models of Various Technology Suppliers Syngas over the fence
Technology owner provides capital investment and operating services
Cost of syngas may be tied to fuel cost, escalation, other factors
Also oxygen over the fence Licensing
Technology owner provides equipment design and performance guarantees for equipment
Owner assumes risk of integrated unit performance Turn key EPC with performance guarantees
Technology owner provides engineering and design of integrated unit and all components
Technology owner also assumes cost and schedule risk Guaranty of total unit performance: inputs vs. outputs
Gasification Technology Options
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Commercial Technology Choices Slurry fed – Conoco, GE
Slurry fed technologies suited to high rank fuels Dry fed – Shell
Better heat rate, longer injector life Technology suited for lower rank subituminous coals as well
as high rank fuels Heat Recovery/Integration
Quench – GE Chemical production applications
Radiant syngas cooler – GE, Conoco, Shell Heat recovery for power generation in steam turbine
Convective syngas cooler – GE Availability impact due to plugging – not selected for
reference plant
Gasification Technology Options
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Current Configuration – AEP East IGCC
Net output 621 MW, Heat Rate 8,890 Btu/kWh (2,240 kcal/kWh) Target turndown to 40% of full load, and load following operation
- Broad fuel specification (eastern bituminous coal, petcoke) GE (formerly Texaco) Gasifiers
- Two radiant + quench gasifiers – no spare- Operating pressure 625 psi (43 bar)
Turbine-Generators- Two GE 7FB combustion turbines - 232 MW each
Evaporative inlet cooling- Single steam turbine – 300 MW
Emissions Control Systems- Selexol acid gas removal system for sulfur (H2S) removal w/COS reactor
- Activated carbon bed for mercury removal- Syngas moisturization, nitrogen diluent for NOx control
Space provisions for future polygeneration and CO2 capture
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The gasifier operates at approximately 625 psi (43 bar) and 2550oF (1400oC)
Gasifier volume 1800 cubic ft (50.4 cubic meters)
The RSC generates high pressure steam by cooling the hot syngas from the gasifier from 2550oF to 1250oF (1400oC to 700oC).
The RSC vessel is lined with waterwall panels along the inside perimeter of the vessel as well as some in the radial direction. The steam is generated in the RSC and circulated to the external steam drum.
The RSC concept has been demonstrated at plants in Germany as well as Coolwater and Polk Power in the USA. The vessel is about 6 m in diameter and 30-40 m long.
The AEP RSC design is different than the Polk Power design because it has an internal water quench section at the vessel bottom which further cools the syngas at about 450oF (230oC).
Gasifier/Radiant Syngas Cooler (RSC)
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When the gasifier load changes the oxygen to slurry ratio remains constant because the oxygen to carbon ratio is part of the control system.
The gasifier is connected to the RSC through a flange connection. The vessel heads and flanges are protected by the refractory lined transfer line.
The molten slag from the gasifier solidifies as it cools inside the RSC, and is collected in a water quench section at the bottom of the RSC. The slag and fines are removed through a lockhopper (LH) system which is automatically cycled to collect the slag at high pressure. The LH is then isolated and depressurized, and slag is dumped. The LH is re-pressurized and returned to collection mode. There will be 2 to 3 LH cycles per hour, depending on the fuel ash content.
Gasifier/Radiant Syngas Cooler (RSC)
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The velocity from the gasifier to the RSC decelerates from 15-20 feet per second (5-6 meters per second) to less than 3 feet per second (1 meter per second).
The velocity profile of the syngas from the gasifier to the RSC is based upon jet flow calculations. The jet velocity when it hits the waterwall cannot be so high that it causes erosion and cannot be low enough to allow ash deposition.
Gasifier/Radiant Syngas Cooler (RSC)
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95% oxygen purity for oxygen to gasifier – 98% other uses Economy, ability to maintain design composition when changing
loads ASU will consume ~110 MW depending on fuel and ambient conditions Air integration
Approximately 25-30% of flow to main air compressor supplied by extraction air from CT at design point (ISO)
Lessons learned from Polk Unit output curtailed due to lack of ASU capacity
ASU Turndown Compressor limited to approximately 85% Can adjust air extraction to extend range
No plans to produce other gases for sale Storage capacity
8 hours full load oxygen use Nitrogen for purge, transfer CT to natural gas in case of ASU trip
Air Separation Unit
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Fuel Flexibility The gasification process can utilize any fuel containing hydrocarbons
Coal Biomass Petroleum Byproducts
Petcoke The AEP East IGCC design fuels include Northern Appalachian and
Illinois Basin bituminous coals and the ability to blend petcoke with coal
Technology selection is dependant on fuel Eastern Coal – Low moisture content, high heating value
Many eastern coals have high ash fusion temperatures, requiring the use of fluxant
Some eastern coals have high chloride content Lignite & PRB coals – High moisture content, high ash content, not
currently suited for slurry fed gasifiers, due to ability to achieve desired slurry concentration.
Gasification Fuel Options
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Impact of coal specifications
Coal ash fusion temperature - This is a slagging gasifier design which requires a less than 2500oF (1370oC) reducing ash fusion temperature. Coals with this low fusion temperatures are found in the Northern Appalachian and Illinois Basin. Coal in the Central and Southern Appalachian basin have high fusion temperatures and would require the addition of fluxant to suppress the ash fusion temperature. A fluxing system is currently not part of the AEP IGCC design.
Sulfur content range - The design sulfur content of the fuel effects the sizing of the Acid Gas Removal (AGR) and Sulfur Recovery Unit (SRU) systems. Coals from the Northern Appalachian and Illinois Basin have high sulfur content coals. The AEP coal specification allows for coals with sulfur content up to 7.5 lb SO2/mmBtu (5.26% wt. sulfur dry basis).
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Impact of coal specifications (cont.)
Chloride content Coals from the Illinois Basin have high levels of chlorides. For
IGCC technology, the chlorides are removed in the syngas cleaning systems. High chlorides may require the selection of higher alloys in certain systems, and may increase water usage. The AEP design provides for coal chlorides up to 3500 ppm (0.35% wt.).
Coal ash percentage Nearly all of the ash is removed from the gasifier as slag. The ash
content of the fuel determines the size of the slag handling systems. The AEP specification allows for ash content in the fuel up to 12%. This allows the use of many run-of-mine coals, with no coal washing needed.
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Coal Prep System
Rod mills are used to mix and pulverize the coal. Dry coal and processes water is added to the rod mills. Coal slurry is then pumped into the gasifier at operating pressure.
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There are two syngas/natural gas fired combustion turbines. The combustion turbine selected is the GE 7FB designed for syngas. Each turbine can generate 232 MW, utilizes air inlet cooling, and uses a hydrogen cooled generator.
Nitrogen from the ASU and steam will be added to the syngas to increase mass flow and reduce the flame temperature. This feature enhances the output of the turbine, and allows for lower NOx operation.
The HRSG is a two pressure design, which converts the heat from the exhaust of each combustion turbine into superheated steam. The HRSGs also receive steam from the gasification process.
The steam turbine used is a GE D-111 with 40 inch (1 m) last stage blades. Steam in condensed by a water tube condenser. The steam turbine output is 310 MW, and uses a hydrogen cooled generator.
The cooling tower provides circulating water for both the steam turbine condenser, and cooling loads from the ASU. The cooling tower is a mechanical draft type.
Power Block
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NOx 15 ppm NOx in exhaust gas (15% O2 ref) on syngas
25 ppm NOx in exhaust gas (15% O2 ref) on natural gas SO2
>99.5% removal 40 ppm total sulfur in syngas (H2S + COS)
0.02 lb SO2/mmBtu
~4 ppm total sulfur in exhaust gas (10% O2 ref) Particulates (PM10 and PM2.5) Mercury
Activated carbon bed for mercury removal Expect 90% of mercury in syngas
Other Hazardous Air Pollutants Startup considerations Environmental performance without CO2 removal comparable to
supercritical PC equipped with state of the art emissions controls
Air Emissions
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Acid gas technology choice MDEA – amine technology – chemical solvent Selexol – allows for deeper sulfur removal – physical solvent Rectisol – methanol solvent
Cost vs. effectiveness Depends on gas composition, sulfur removal desired
Capital O&M Effect on output
COS Hydrolysis Effects on total emissions COS removal in AGR varies from <10% (MDEA) to 100% (Rectisol) COS reactor required to cost effectively meet 99% sulfur removal
in MDEA and Selexol systems
Sulfur Removal
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Diluent injection Nitrogen – from ASU – increase CT mass flow/output CO2 – maximize slip in AGR – increase CT mass flow/output Steam – impact on steam cycle output
SCR Cost Uncertainty of catalyst formulation for coal derived syngas Interaction with sulfur
Ammonia salts produce particulate emissions, may deposit in HRSG
Other Air Emissions Particulate – salts, H2SO4
Ammonia – 5 ppm slip (ref 15% O2)
NOx Control
26
Flare Options
Flare used to destroy raw or combustible gases during startup, shutdown, and transient events
Flare emissions result in elevated ground level concentrations of SO2
Operational and hardware modifications to reduce duration of flare events
Visibility low during daylight hours
Elevated Flare (AEP plant) Flare height 200 ft (60 m)
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Flare Options
Ground Level Flare
Enclosed Flare
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Current plan to discharge wastewater to Ohio River The discharge permits and their associated limits are set by the
state where the plant is sited The Ohio River Valley Water Sanitation Commission (ORSANCO) is
an organization that tries to address inconsistencies between states and proposes pollution control standards (www.orsanco.org).
ORSANCO discharge targets are set to protect the users of the water and avoid water quality degradation
The target values for some elements are very low
Wastewater Effluents
Parameter River Max Dissolved
River Max Total
Grey Water Cool Water
IGCC
Discharge Target
Average/Max
Mercury, ppt 1.93 13.1 630 10/20
Beryllium, ppb <0.2 <0.2 230 0.1/0.2
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Uncertainty of grey water composition Samples not available for jar tests Potential interferences in treatment Uncertainty on levels achievable level of treatment Detection Limits Historic data
Toxicity Chlorides in the effluent Daphnia survivability
Temperature
Wastewater Treatment Challenges
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Wastewater Treatment Process
Ammonia stripping
Grey Water Pretreatment
Wastewater treatment
Metals Removal
Biological treatment Filter
Final Effluent Sump
RetentionPond
LimeSulfide
Phosphoric acidAeration
Sludge Thickening
Filter Belt Presses
Makeup watersludge
Sludge to landfill
Holding Tank
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Zero liquid discharge system currently under evaluation Reduced effluent to river Capital cost still to be determined Uncertainties in grey water composition would also affect this
design Potentially higher auxiliary power consumption for this system Possibility of recovering metals for sale
Wastewater Effluents
32
Byproduct disposition (Primarily Slag and Sulfur) Slag is the primary waste product produced by the IGCC process
The carbon content of the slag is the key parameter that effects the ability to market the product.
Slag is sold as roofing materials, grit blasting materials, and concrete additive. The acceptable carbon content for each of these applications is critical to its marketability.
The AEP plant will be designed with landfill capacity for disposal of slag.
Sulfur is a byproduct of the AGR system/sulfur recovery system. Sulfur can be produced as sulfuric acid, molten sulfur, or
pelletized or prilled sulfur. Local market condition will dictate the form of sulfur produced.
The AEP plant will be designed to produce molten sulfur. Landfill capacity will include space for sulfur disposal.
Solid Effluents
33Ohio River
Coal Storage
Unit 1
Unit 2
AEP Work Scope
GE/Bechtel Work Scope
UNIT 2 COOLING
TOWER FUTURE
UNIT 1 COOLING
TOWER
SRU – Sulfur Recovery Unit
Visitors Center
Truck Unloading
Future
Barge Unloader #1
Future
Barge Unloader #2
Flare
Flare
SRU
GSPB
PB
Maintenance Building/ Warehouse
Admin Building/ Control Room
345 KV Switchyard
Landfill Storage Pile
-345 KV Switchyard-Slag Handling & Storage-Coal Unloading-Coal Storage-Water Intake
TGT – Tail Gas Treating Unit AGR – Acid Gas Removal ASU – Air Separation Unit PB – Power BlockGS - Gasifier
River Water Intake House
ASU
TGT
AGR
Fluxing System
Future
Future
Future
CO2
CO2 -Future CO2 CaptureEquipment
Future Polygen
Future Polygen
Smathers
Great Bend IGCC Plant Scope of Work
34
Great Bend - Site with Landfill & Property Lines
35
Mountaineer IGCC Plant
36
Great Bend IGCC Plant
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Startup Fuel
Natural gas to warm gasifier, electric demand for ASU Emissions
Time to place sulfur systems in service Time to start up
Over 70 hours for cold startup Turndown
Target to 40% net Availability
Target 85% Maintenance requirements
Refractory replacements Hot gas path turbine inspections
Production costs On par with conventional PC
Operational Considerations
38
Evaluate capital cost for design features vs. benefits Screening Valuations
Capacity $1.5 million/MW Heat rate $5.0 million/100 Btu/kWh
($5.0 million/25.2 kcal/kWh) Availability $3.5 million/percentage point of availability
1st quarter 2005 – based on operating characteristics of similar sized plant in Ohio River Valley
Critical assumptions – fuel cost, capacity factor, production cost
Economic Considerations
39
• Value of emissions credits is not included. • Assumes 80% capacity factor for PC and IGCC, 25% for NGCC. • EPC is overnight engineer, procure, construct 4Q2004. • Total project cost includes owner’s costs and AFUDC. • Transmission upgrades not included. • Results of AEP analysis based on EPRI studies.
Generating Technology Options:Cost of Electricity without CO2 Capture
PC
Supercritical
IGCC NGCC
Capacity, MW net 600 600 500
Fuel cost, $/mmBtu 1.50 1.50 6.00
Full Load Heat Rate, Btu/kWh 8,691 8,500 7,040
EPC Cost, $/kW 1,192 1,450 455
Total Project Cost, $/kW 1,442 1,737 550
Operations and Maintenance, $/MWh 8.49 9.63 6.66
Cost of Electricity, $/MWh 53.11 60.33 88.25
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CO2 Capture
Carbon capture (CO2) in IGCC system (syngas fuel) is proven and inexpensive:
Convert CO in syngas to CO2 using water-gas shift reactionCO + H2O CO2 + H2
Remove CO2 before the fuel is burned in the CT Lower volume of gases for processing Higher concentration of CO2
Either chemical (amine) or physical solvents IGCC stands out due to lower cost of CO2 removal
Commercial application depends on H2 burning CT technology
CO2 capture in flue gas (PC & NGCC application) more difficult: Flue gas volumes larger – lower pressure, combustion air Low CO2 partial pressure – physical solvents are impractical Amines (MEA or MDEA) applicable – but overall system becomes
expensive More work is needed on CO2 capture technology & cost from flue
gas in PC & NGCC applications
41
CO2 Capture
Recent work indicates significant impact on cost of electricity to implement CO2 capture and sequestration:
Price adder will depend on the extent of CO2 capture
Cost of electricity for IGCC plants with CO2 capture expected to be lower than PC with CO2 capture
42
• Value of emissions credits is not included. • Assumes 80% capacity factor for PC and IGCC. • Results of AEP analysis based on EPRI studies.
Generating Technology Options:Cost of Electricity with CO2 Capture
PC
Supercritical
IGCC
Capacity, MW net 425 501
Fuel cost, $/mmBtu 1.50 1.50
Full Load Heat Rate, Btu/kWh 12,100 10,700
Cost of Electricity, $/MWh 94 85
CO2 Removal Cost, $/ton 22 16
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No pre-investment for carbon capture Space in plot plan to be left for retrofit systems Clean shift will result in greater impact to steam cycle
Carbon Capture from Syngas
Gasifier Low-temperature syngas cooler (LTGC)
Low-pressure compressor (LP comp)
High-pressure compressor (HP comp)
Acid-gas removal (AGR)
Sulfur removal unit (SRU)
COAL
Tail-gas unit (TGU)
H2-rich syngasto Power Block(CT/HRSG)
Syngas Saturation
ShiftReactor(s)
MPsteam
CO2Absorber
CO2to capture
For internal utilization
N2 blending equipment
Syngas compressor
N2dilution
NEW RETROFIT UNITS
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Maintaining full load on gasifier at all times
Synergies with other stakeholders
Syngas contains H2, CO, CO2
Important building blocks in chemical manufacturing Potential to replace natural gas, petroleum in chemical
processes Polygeneration – production of power and chemicals at an IGCC
plant
Gases from air plant Argon Nitrogen Oxygen
Polygeneration Options
45
Screening Study considered production of hydrogen, methanol, urea Methanol selected for further consideration
Ease of storage/transport Possible in-plant use
Start up fuel AGR solvent
Study assumptions Need to cycle daily Produce fuel grade product Conventional process
Capacity factor
Polygeneration Options