Meeting the Carbon Challenge: AEPAEP s’s Perspective ...€¦ · AEP is Strongly Committed to...
Transcript of Meeting the Carbon Challenge: AEPAEP s’s Perspective ...€¦ · AEP is Strongly Committed to...
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Meeting the Carbon Challenge: AEP’s PerspectiveAEP s Perspective
Energy SummitgyAdvancing Domestic Resources
in anE f C b Ch llEra of Carbon Challenges
Michael W RencheckMichael W. RencheckSVP – Chief Nuclear Officer
American Electric Power
December 4, 2007
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AEP Company Overview
Natural Gas/Oil
Nuclear6%
Coal/Lignite67%
Gas/Oil24%
6%Pumped Storage/
Hydro/Wind3%AEP’s Generation FleetAEP s Generation Fleet
38,388 MW Capacity
5.1 million customers in 11 statesIndustry-leading size and scale of assets:
A t SiIndustry
R k
2
Asset Size RankDomestic Generation ~38,300 MW # 2Transmission ~39,000 miles # 1Distribution ~208,000 miles # 1
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AEP is Strongly Committed to Addressing GHG and Environmental SustainabilityGHG and Environmental Sustainability
“With Congress expected to take action on g pgreenhouse gas issues in climate legislation, it’s time to advance this technology (CO2 Capture) gy ( 2 p )for commercial use”
Mike MorrisMike MorrisAEP President, Chairman and CEO
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EPRI CO2 Reduction “Prism”2030 CO2 below 1990 level
3500
2030 CO2 below 1990 level
Achieving all targets is aggressive, but potentially feasible
2500
3000
tons
)
EIA Base Case 2007
2000
ectr
ic S
ecto
r(m
illio
n m
etric
t
Technology EIA 2007 Reference Target
Efficiency Load Growth ~ +1.5%/yr Load Growth ~ +1.1%/yr
Renewables 30 GWe by 2030 70 GWe by 2030
1000
1500
U.S
. Ele
CO
2 Em
issi
ons Renewables 30 GWe by 2030 70 GWe by 2030
Nuclear Generation 12.5 GWe by 2030 64 GWe by 2030
Advanced Coal GenerationNo Existing Plant Upgrades40% New Plant Efficiency
by 2020–2030
150 GWe Plant Upgrades46% New Plant Efficiency
by 2020; 49% in 2030
CCS N Wid l D l d Aft 2020
500
CCS None Widely Deployed After 2020
PHEV None10% of New Vehicle Sales by
2017; +2%/yr Thereafter
DER < 0.1% of Base Load in 2030 5% of Base Load in 2030
4
01990 1995 2000 2005 2010 2015 2020 2025 2030
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AEP is Pursuing a Portfolio of Options to Address SustainabilityOptions to Address Sustainability
Technology EIA 2007 Reference Target AEP Plan
Efficiency Load Growth ~ +1.5%/yr Load Growth ~ +1.1%/yr DSM: 1000MW reduction in demand by 2012
Renewables 30 GWe by 2030 70 GWe by 2030
Wind PPAs through 2015; 1610MW nameplate or 232MW capacity for planning purposes.
Also, voluntary green energy tariffs (Ohio program started 2007)
Nuclear E l ti f COLNuclear Generation 12.5 GWe by 2030 64 GWe by 2030 Evaluation of COL
Advanced Coal Generation
No Existing Plant Upgrades
40% New Plant Efficiency
by 2020–2030
150 GWe Plant Upgrades46% New Plant Efficiency
by 2020; 49% in 2030
1246MW IGCC (WV and OH) by 2017600MW (447MW AEP) USC Turk plant (AK) by 2011
y
CCS None Widely Deployed After 2020
Chilled Ammonia: Mountaineer (WV) 2009 & Northeastern (OK) 2012
FutureGen :DOE along with AEP and Alliance members 2012
Oxy-coal 2015 (Sub-critical PC unit retrofit)
PHEV None10% of New Vehicle Sales
by 2017; +2%/yr Thereafter
Joined Electric Drive Transportation Association (EDTA) in May 2007
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DER < 0.1% of Base Load in 2030 5% of Base Load in 2030
Pursuit of NaS Energy Storage – 25MW of storage by 2010 and 1000MW of other storage/fuel cells by
2020
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AEP Leadership in Technology: IGCC/USC and Future Gen
NEW ADVANCED GENERATION•IGCC---AEP was the first to announce plans to build two 600+ MW IGCC commercialto build two 600+ MW IGCC commercial scale facilities in Ohio and West Virginia by the middle of next decade
•USC--AEP will be the first to employ the new generation ultra-supercritical (steam temperatures greater than 1100oF) coal plant in Arkansas
•FutureGen - First Near Zero Emissions•FutureGen - First Near Zero Emissions Hydrogen/ Electric (coal-fueled IGCC with CCS)-DOE along with AEP and Alliance members. COD 4Q 2012; then 3 yrs (2013-2015) CO2 storage; and another 2 yrs (2016-
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2015) CO2 storage; and another 2 yrs (2016-2017) for long term storage validation
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Efficiency and CO2 Emission Ratesy 2
7Increasing Generation Efficiency
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Carbon Intensity for Different Systemsy
CO2 Reduction Necessary to Achieve NGCC Emission Levels2.5 US Coal Fleet
2.0
(62%)USC
(57%) IGCC (54%)
1.5
(lb/k
Wh) NGSC
(36%)
730
980
,500
,980
0400.5
1.0
CO
2
H.R
. = 8
,7
H.R
. = 8
,9
H.R
. = 1
0,
H.R
. = 1
0,
H.R
. = 7
,0
0.0
0 5
Nuclear /Renewables
Nat. GasCombined Cycle
Nat. Gas SimpleCycle NGSC
US Coal FleetAverage
UltraSupercritical
IGCC(Bituminous)
8Note: H.R.= Heat Rate (efficiency). Values represent typical heat rates, used here for illustrative purposes only.
Renewables Combined Cycle,NGCC
Cycle, NGSC Average Supercritical,USC
(Subbituminous)
(Bituminous)
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CO2 Capture TechniquesPost-Combustion Capturep
• Evaluated available CO2 capture options, considering both commercial and emerging technologies• Commercially available Amine based technologies
• Currently installed on much smaller scale than PC plant and other industrial applications
• High parasitic demand – reduced unit outputg p p• Conventional Amine ~25-30%• High steam consumption for regenerating solvent (60% of
parasitic load) • Requires very clean flue gas• Requires very clean flue gas
• Chilled Ammonia Process (CAP)• Demonstration scale under construction at WE Energies Pleasant
Prairie Plant (complete end of 2007)Prairie Plant (complete end of 2007)• Aspirational Goal - Lower Parasitic Demand
• Power and steam parasitic load ~ 10-15%• Lower steam consumption (35% of parasitic load)
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p ( p )• Requires clean flue gas but less sensitive to contaminants• Flue gas cooled to 40 to 60 oF
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Alstom’s Chilled Ammonia ProcessPost-Combustion CapturePost Combustion Capture
(Ammonium Bicarbonate)
CO2Solvent
CO2
R t
CO2
Ab bFlue GasFrom FGD
Regenerator(203–250oF)
Absorber(40-60oF)
Conc. CO2To Storage
Solvent
10(Ammonium Carbonate – “Baker’s Ammonia”)
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CHILLED AMMONIA PROCESS
Regenerators
Flue GasChillers
CO2
CompressorsCO2
Absorbers
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Chilled Ammonia Technology Program
2009 Commercial Operation 2012 Commercial OperationPhase 1 Phase 2
1300 MW Mountaineer Plant (WV)
450 MW Northeastern
Plant (OK)
Chilled Ammonia
Chilled Ammonia
MOU (Alstom) MOU (Alstom)
20 MWe 200 MWe(90% removal
Project Validation Commercial Scale Retrofit200 MW l ( tt l t i )
CO2 (Battelle) CO2 (EOR)Slip Stream (90% removal
of 50% slip stream)
• 20 MWe (megawatts electric) scale (a scale up of Alstom/EPRI 5 MWt (megawatts thermal) field pilot, under construction at WE Energies)
• ~100 000 tonnes CO2 per year
• ~ 200 MWe scale (megawatt electric)• ~1.5MM tonnes CO2 per year• Approx. capital $250 – $300M (CO2 capture
& compression)• Energy penalty ~ 35–50MW steam, 25–• ~100,000 tonnes CO2 per year
• In operation 2Q 2009• Approximate cost $80 – $100M• CO2 for geologic storage
Energy penalty 35 50MW steam, 2530MW compression
• Retrofit NOx Controls and FGD Required: $225 – $300M (required for capture equip.)
• CO2 for Enhanced Oil Recovery (EOR) or geologic storage
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geologic storage
Phase 2 will capture and sequester 1.5 Million metric tons CO2/year
Phase 1 will capture and sequester 100,000 metric tons of CO2/year
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CO2 Capture TechniquesOxy Coal Firingy g
• Modified-Combustion Capture – Oxy Coal Firing• Key Points
• Technology not yet proven at commercial scale• Creates stream of high CO2 concentration• High parasitic demand, >25%
D t ti S l• Demonstration Scale• 10 MWe scale• Teamed with B&W at its Alliance Research Center and several
other utilitiesother utilities• Demo completion 4Q 2007
• Commercial Scale• Feasibility study in progress y y p g• Retrofit on existing AEP sub-critical unit (several available)• 150 – 230 MWe scale retrofit• 4,000 – 5,000 tons CO2 per day
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• Retrofit targeted between 2013 and 2015
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CO2 Capture Techniques
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FutureGen’s Water-Gas Shift ProcessPre-Combustion Capture
Water-GasShift
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CO2 Capture TechniquesPre-Combustion CapturePre Combustion Capture
• Pre-Combustion Capture
• IGCC with Water-Gas Shift – FutureGen Design• IGCC with Water-Gas Shift – FutureGen Design
• Key Points• Most of the processes commercially available in• Most of the processes commercially available in
other industrial applications
• Have never been integrated
• Turbine modified for H2-based fuel, which has not yet been proven at commercial scale
• Creates stream of very high CO concentration• Creates stream of very high CO2 concentration
• Parasitic demand (~15%) for CO2 capture - lower than amine or oxy-coal options
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FutureGen’s Water-Gas Shift ProcessPre-Combustion Capture
Mountaineer IGCC without CO2 Capture
Space for Space for Water-Gas
Shift
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FutureGen’s Water-Gas Shift ProcessPre-Combustion Capture
Mountaineer IGCC with CO2 Capture
CarbonCarbonDioxideDioxide
HydrogenHydrogenWaterWatershiftshift
ReactorReactor
COCO Water GasCOCO22
AbsorberAbsorberWater-Gas
Shift
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CO2 Storage Key Points
• Challenges with storageg g• Geology Dependency
• A 500 MW power plant could require a many wells at a spacing of several thousand feet or more
• Not yet proven in large scale or in long-term• Uncertainty on environmental fate and long term
interaction of contaminants in product CO2 with saline p 2(ammonia, water, SOx)
• Capacity and injection rates very site-specific• Long-term liability and legal ownership are points not g y g p p
yet resolved on federal or state level• Competition with natural low cost sources of CO2 for
EOR opportunities
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pp
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Enhanced Oil Recover (EOR)
Graphic courtesy of USDOE National Energy Technology Laboratory
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Examples of Relative GHG Mitigation Costs for Power Sector
• Carbon Capture w/ Geologic Sequestration$40+
• Other renewable, advanced geothermal and/or solar
• Carbon Capture for Enhanced Oil ROil Recovery
• New Biomass Generation• Dispatch of additional gas vs.
i ffi i t l
CO
2e
inefficient coal• Biomass Co-firing• Biological Sequestration (e.g.
Fo est )
$/to
n
Forestry)• New Wind• Nuclear• Energy Efficiency• Methane Offsets$0
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Questions ?
Serious issues require realistic discussion to provide commercial p
solutions.