1. Mountaineer Commercial Scale Carbon Capture &
Storage (CCSII) Project Phase I
Lessons Learned
November 8 & 10, 2011

2. AEP Overview
 5.2 million customers in 11 states
 Industry leading size and scale of
assets:
#2 Domestic generation with 38,000 MW
#1 Transmission with 39,000 miles
#1 Distribution with 216,000 miles
 Coal & transportation assets
Over 7,500 railcars involved in operations
Own/lease and operate over 2,850 barges & 75
towboats
Coal handling terminal with 20 million tons of
AEP Generation Capacity Portfolio
capacity
Consume 76 million tons of coal per year Coal/ Gas/ Nuclea Other –
 18,712 employees Lignite Oil r (hydro,
wind, etc.)
66% 22% 6% 6%
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3. Mountaineer Plant
Located in New Haven WV Owned and Operated by Appalachian Power Company
Single Unit plant 1300 MWnet pulverized coal unit
Single Reheat Supercritical Steam Cycle, burns eastern bituminous coal
3515 psia 1000/1050 oF,(240 bar, 537/566 oC)
Full suite of emissions control equipment, ESP, SCR, Wet FGD and Trona for SO3
mitigation.
Deep well characterization activity in 2002
20-MW CO2 capture and storage validation effort by Alstom and AEP in 2010/2011
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4. MT CCS II Project Overview
Purpose: Advance the development of the Alstom Chilled Ammonia Process
(CAP) CO2 capture technology and demonstrate deep saline CO2 storage and
monitoring technology at commercial scale
Project Participants
AEP, USDOE, Alstom, Battelle, WorleyParsons, Potomac Hudson, Geologic
Experts Advisory Team
Location: Mountaineer Power Plant and other AEP owned properties near
New Haven, WV
Preliminary cost estimate: $668 million
50/50 DOE cost share up to $334M
Project Technical Objectives
90% CO2 removal from the stack gas
Store 1.5 million metric tons of CO2/year
Demonstrate commercial scale technology
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5. AEP CCS Commercialization Project
New Haven, WV
Sequestration: Battelle is Storage Contractor
2 primary deep saline reservoirs
~7,800 and ~8,200 feet below the surface
~1,500,000 tons CO2 per year
Pipeline system with off-site wellheads
Geologic Experts Advisory Group:
Battelle, CONSOL, MIT, Univ. of Texas, Ohio State, WVU, Virginia
Tech, LLNL, WV Geo. Survey, OH Geo. Survey, WV DOE, NETL, RWE,
& CATF
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6. 3D Model of Capture System
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7. 3D Model of Capture System
Capture System requires approximately 13 acres for the 260 MWe Project.
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8. CCS Equipment at Mountaineer
Original Plant and 260-MWe Chilled Ammonia System
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9. CO2 Transport & Storage System
Borrow and Jordan Tract sites are the targeted CO2 injection sites; East Sporn site is a back-up contingency site.
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10. Scope
Capture System Storage System
Chilled Ammonia Process Wells
Equipment, Tie-in Duct, (2) CO2 Injection wells
Storage Tanks, Buildings & (9) Deep CO2 Monitoring
Compression Equipment (4) Intermediate CO2
80,000 cy Concrete Monitoring
9,500 tons Struc. Steel (8) Groundwater monitoring
118,000 ft Piping Pipeline
127,000 ft Conduit/Cable 10 miles to furthest injection
Tray point
1.2-MM ft Electrical Cable
A total of 2.2-million craft labor hours for the capture and storage systems, at 1.2 and 1.0 million hours, respectively.
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11. MT CCS II Phase I
Technical Approach
Chemical Plants Power Plants:
Uniform product from a Production based on demand
uniform feedstock vs. Cyclical based on weather,
time of day, etc.
Stable production rate Frequent load adjustments
with consistent vs. Base load one day, load-
production schedules following the next.
Process variables Variable feedstock (coal)
minimized to reduce vs. Chemical composition,
impacts. heating value, moisture
content, etc.
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12. MT CCS II Phase I
Technical Approach
Minimize impact on existing unit.
Variable coal supply, which impacts the SO3 and trace
element consideration on the project.
Avoid the impact of an additional emission source and
the associated permitting implications
Time pressures prevented some optimization
opportunities
Integration Concepts Considered
Heat Recovery from Flue Gas
CO2 heat of compression recovery
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13. Lessons Learned
Reagent Study
Options considered:
Anhydrous Ammonia
Aqueous Ammonia
Ammonium Carbonate
Evaluation Results:
Anhydrous Ammonia was selected
Reduces Water balance issues
RMP considerations present as a result of Refrigeration
System
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14. Lessons Learned
Clean Flue Gas Exhaust
CAP Exhaust options considered
Existing stack
New stack close coupled to process island
Existing plant hyperbolic cooling tower
Evaluation Results:
Hyperbolic cooling tower option eliminated from consideration
Perceived technical and environmental risks
Existing stack option and new stack options were both technically
acceptable
Team initially recommended a new dedicated stack.
Uncertainties associated with modeling/permitting of a new stack
For treating higher percentages of flue gas, a dedicated exhaust point
may be required as the technical difficulties surrounding mixing of
flue gas streams and gas stream temperature becomes a concern
Return to the existing stack was basis for the estimate
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15. Lessons Learned
Water Management
Grey water management is a significant challenge
Fresh water make-up for evaporation and losses do not require
added make-up capacity
To make grey water marketable, there is a need to concentrate the
ammonium sulfate content
Possible concentrate to solid ammonium sulfate
Concentrate up to 40% ammonium sulfate solution, chosen as
the best cost option for use as a marketable fertilizer.
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16. Lessons Learned
Misc. Capture System
For the 20% slip stream, steam provided from the existing unit is
feasible. For a 100% gas stream, a separate steam source will
likely be needed.
Studied various steam source options. For this project size and this
unit, steam was taken from the IP to LP crossover.
Condensate return must be cooled for reintroduction to the existing
power plant cycle if to the hotwell, or introduced back into the low
pressure feedwater heater system. Introduction into the feedwater
heater system was the basis of estimate.
A buffer tank was included to prevent plant cycle contamination from
the ammonium carbonate/ammonium bicarbonate reagent
Dedicated control room was recommended due to the complexity
of the system and low level of interface needed between the
existing unit and the carbon capture equipment
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17. Lessons Learned
CO2 Compression
Injection well pressures have large variation, and Injection
pressures in the 1200 – 1500 psi range are expected early
in the life of the target injection wells
Maximum injection pressure into the geological formations
targeted for this project is expected to be 3000 psi.
Compression to an intermediate pressure, followed by
variable speed pumping to the final injection pressure
offers the greatest flexibility and efficiency over the life of
the system as compared to full compression to the
maximum expected injection pressure.
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18. Lessons Learned
CO2 Sequestration
Identified a new geologic horizon (lower Copper Ridge) for CO2
sequestration which was previously not known as a storage target
The deeper formations in this region (greater than 5,000ft) show low
potential for large scale CO2 sequestration due to low permeability
Preliminary simulation results show 1.5 million metric tonnes/year CO2
injection for 5 years can be achieved with injection pressure lower than
the fracture pressure of the formation
Geophysical techniques such as surface seismic have limitations
Surface seismic cannot resolve thin horizons
Mountaineer formations are only ~30ft in thickness
Drilling a deep well is always associated with uncertainty
Un-expected delays can occur during this process
Reservoir tests are crucial during the characterization process
The emphasis of the subsequent projects should be on obtaining more
‘injection data’
Results from numerical models must be calibrated with real data
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19. Future plans of CCS for AEP
Questions
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