1. New Generation Strategy
IGCC Technology
Presented by:
Mary Zando, Manager
Chemical Systems,
New Generation Projects
Dan Duellman, Manager
Mechanical & Balance of Plant,
Monty Jasper, Manager
New Plant Development Projects
APP Site Visit
October 30 – November 4, 2006

2. 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
Revenues: $14.5 billion
Assets: $37 billion
US customers: million
US employees: ,000
Source: AEP 2003 Annual Report
Monty
AEP feels the obligation to be a leader in developing the next generation of technology to serve our customers
We have the financial strength to advance technology without unreasonable risk to our company

3. The American Electric Power System
Monty
AEP feels the obligation to be a leader in developing the next generation of technology to serve our customers
We have the financial strength to advance technology without unreasonable risk to our company

4. 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
Revenues: $14.5 billion
Assets: $37 billion
US customers: million
US employees: ,000
Source: AEP 2003 Annual Report
Monty

5. 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
Dan
Almost 3 years ago New Generation Development was asked, “Where is the best site in the AEP East System territory to build an IGCC Power Plant?”
We reviewed some previous siting studies, which were several years old;
Decided it was time to redo the studies.
Team made up of Engineering disciplines Commercial operations, Land Management, Legal
Sites were evaluated for available land … fatal flaw
Reduced list from 25+ to 15
Developed 25 evaluation criteria
Third party consultant and a core group of Team members traveled to the sites.

6. 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)
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)
rail loop
150 (60)
coal yard
40 (16)
acres (hectares) inside rail loop
solid waste disposal
300 (121)
Total (rail delivery)
390 (158)
600 (243)
Total (barge delivery)
280 (113)
490 (198)
Operating staff
125
200
full time equivalent employees
Dan
The siting Team used this design basis for the evaluation of the sites.

7. 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
Dan
Here are 26 ranking criteria presented in 7 general categories.
These were developed from a very detailed list of about 57 criteria. These were picked for use in our study as those that could be easily researched and evaluated for each site in a period of 2 – 3 months.
Each of the criteria was defined with a a list of musts and wants. Those musts were minimum requirements for the evaluation and scoring; wants are desired but not required. Example
Topography – Must
Sufficient land must be available for the plant footprint and associated facilities. Ground slope across the site, including material storage but excluding solid waste disposal, must not be more than 5% or less than 0.5%.
Topography – Want
Minimize average ground slope (beyond 0.5%) and fill requirements in order to minimize costs for earthwork, retaining walls, erosion control, drainage, roadwork, and track work.
Expandability – Must None
Expandability- Want
Site should have room for expansion with at least one unit beyond base capacity (1,000 MW).

8. Site Selection Ranking Criteria
Weighting Factors
Scale of
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 5
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
Only two units can fit on site
Only one unit can fit on site
Dan
Each ranking criteria is assigned Weighting Factor relative to all of the other criteria.
This is a 1 – 10 scale with 10 being the most important
Each criteria has evaluation parameters in order to assign a Rating Factor
Here are two examples:
Topography

9. Results Top Sites by State Mountaineer – West Virginia
Great Bend – Ohio
Carrs - Kentucky

10. Generating Technology Options: Integrated Gasification Combined Cycle (IGCC) Plants
Monty

11. Gasification Technology Options
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
Monty

12. Gasification Technology Options
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
Mary

13. 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 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
Mary

14. Gasifier/Radiant Syngas Cooler (RSC)
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 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).
Mary

15. Gasifier/Radiant Syngas Cooler (RSC)
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.
Mary

16. Gasifier/Radiant Syngas Cooler (RSC)
The velocity from the gasifier to the RSC decelerates from 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.
Mary

17. Air Separation Unit
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
Dan

18. Gasification Fuel Options
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.
Dan

19. 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).
Dan

20. 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.
Dan

21. 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.
Dan

22. Power Block
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.
Dan

23. Air Emissions 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
Mary

24. Sulfur Removal 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
Mary

25. NOx Control 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)
Mary

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)
Mary

27. Flare Options
Ground Level Flare
Enclosed Flare
Mary

28. Grey Water Cool Water IGCC Discharge Target Average/Max
Wastewater Effluents
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 (
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
Mary
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
230
0.1/0.2

29. Wastewater Treatment Challenges
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
Mary

30. Wastewater Treatment Process
Grey Water
Pretreatment
Final
Effluent
Sump
Ammonia
stripping
Holding
Tank
Metals
Removal
Biological
treatment
Retention
Pond
Filter
Lime
Sulfide
Phosphoric acid
Aeration
Makeup
water
sludge
Filter
Belt
Presses
Sludge
Thickening
Sludge to
landfill
Mary

31. Wastewater Effluents
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
Mary

32. Solid Effluents 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.
Dan

33. Admin Building/ Control Room River Water Intake House
Great Bend IGCC Plant Scope of Work
Landfill Storage Pile
Visitors Center
Truck Unloading
Future
AEP Work Scope
345 KV Switchyard
345 KV Switchyard
Maintenance Building/ Warehouse
Admin Building/ Control Room
Slag Handling & Storage
Coal Unloading
Coal Storage
Water Intake
Future Polygen
SRU
Coal Storage
CO2
ASU
TGT
UNIT 1 COOLING
TOWER
AGR
GE/Bechtel Work Scope PB
SRU – Sulfur Recovery Unit
Flare GS
TGT – Tail Gas Treating Unit
Unit 1
AGR – Acid Gas Removal
ASU – Air Separation Unit
PB – Power Block
GS - Gasifier
Fluxing System
Future
CO2 -Future CO2 Capture
TOWER FUTURE
UNIT 2 COOLING
Equipment
Flare
Future
Dan PB
Unit 2
Future
Future Polygen
Barge Unloader #1
Future
River Water Intake House
Barge Unloader #2
Smathers
Ohio River

34. Great Bend - Site with Landfill & Property Lines
Dan

35. Mountaineer IGCC Plant

36. Great Bend IGCC Plant

37. Operational Considerations
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
Dan

38. Economic Considerations
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
Mary

39. Generating Technology Options: Cost of Electricity without CO2 CapturePC
Supercritical
IGCC
NGCC
Capacity, MW net
600
500
Fuel cost, $/mmBtu
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
Mary
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.

40. CO2 Capture
Carbon capture (CO2) in IGCC system (syngas fuel) is proven and inexpensive:
Convert CO in syngas to CO2 using water-gas shift reaction
CO + 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
Mary

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
Mary

42. Generating Technology Options: Cost of Electricity with CO2 CapturePC
Supercritical
IGCC
Capacity, MW net
425
501
Fuel cost, $/mmBtu
1.50
Full Load Heat Rate, Btu/kWh
12,100
10,700
Cost of Electricity, $/MWh 94 85
CO2 Removal Cost, $/ton 22 16
Mary
Value of emissions credits is not included.
Assumes 80% capacity factor for PC and IGCC.
Results of AEP analysis based on EPRI studies.

43. Carbon Capture from Syngas
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
Mary

44. Polygeneration Options
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
Mary

45. Polygeneration Options
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
Mary