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An Overview of An Overview of COCO22 Capture Technology for Capture Technology for
Fossil Fuel Power PlantsFossil Fuel Power Plants
Edward S. RubinDepartment of Engineering and Public Policy
Carnegie Mellon UniversityPittsburgh, Pennsylvania
Presentation to the
EPA Advanced Coal Technology Work GroupWashington, DCFebruary 8, 2007
E.S. Rubin, Carnegie Mellon
Outline of TalkOutline of Talk
• Why the interest in CO2 capture and storage (CCS)?
• What is the current status of CO2 capture technology?
• What options are available for power plants?
• How effective are current capture systems?
• How does it affect other emissions?
• How much does it cost?
• What is the outlook for improved technology?
• What are the key needs to develop these technologies?
E.S. Rubin, Carnegie Mellon
Why the Interest ?Why the Interest ?
• Coal and other fossil fuels will continue to be used extensively for many decades to come—no easy or fast alternatives on a large scale
• CO2 capture and storage (CCS) offers a way to use fossil fuels (especially coal) with little or no CO2 emissions—a potential bridging strategy
• Energy models indicate that including CCS in a portfolio of options significantly lowers the cost of achieving the deep long-term reductions needed to mitigate climate change
E.S. Rubin, Carnegie Mellon
Can We Can We HaveHave Our Cake and Eat it Too?Our Cake and Eat it Too?
Can We Have Our Coal Can We Have Our Coal Without COWithout CO22??
CO2CO2CO2
E.S. Rubin, Carnegie Mellon
Schematic of a CCS SystemSchematic of a CCS System
Energy Conversion
Process
Air orOxygen
Coal orNatural Gas
UsefulProducts
(Electricity, Fuels,Chemicals, Hydrogen)
CO2
CO2Capture &Compress
CO2Transport
CO2 Storage (Sequestration)
- Post-combustion- Pre-combustion- Oxyfuel combustion
- Pipeline- Tanker
- Depl. oil/gas fields- Deep saline reservoirs- Unmineable coal seams- Ocean- Mineralization
E.S. Rubin, Carnegie Mellon
Status of Capture Technology Status of Capture Technology
• CO2 capture technologies are commercial and widely used in industrial processes, mainly in the petroleum and petrochemical industries (e.g., for ammonia production and processing of natural gas)
• CO2 capture also has been applied to several gas-fired and coal-fired boilers (to produce commodity CO2 for sale), but at scales that are small compared to a large modern power plant
• Integration of CO2 capture, transport and geologic sequestration has been demonstrated in several industrial applications, but not yet at an electric power plant
E.S. Rubin, Carnegie Mellon
Current COCurrent CO22 Capture ProjectsCapture Projects
Source: IEA GHG, 2007
What options are available? What options are available?
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Many Ways to Capture COMany Ways to Capture CO22
MEACausticOther
Chemical
SelexolRectisolOther
Physical
Absorption
AluminaZeoliteActivated C
Adsorber Beds
Pressure SwingTemperature SwingWashing
Regeneration Method
Adsorption Cryogenics
PolyphenyleneoxidePolydimethylsiloxane
Gas Separation
Polypropelene
Gas Absorption
Ceramic BasedSystems
Membranes Microbial/AlgalSystems
CO2 Separation and Capture
Choice of technology depends strongly on application
E.S. Rubin, Carnegie Mellon
IPCC Special Report Examines IPCC Special Report Examines COCO22 Capture Technology in DetailCapture Technology in Detail
The Intergovernmental Panel on Climate Change (IPCC) Web Site (www.ipcc.ch) has:
- Summary for Policymakers
- Technical Summary
- Full Technical Report (also available from Cambridge University Press, 2005)
E.S. Rubin, Carnegie Mellon
Leading Candidates for CCSLeading Candidates for CCS
• Fossil fuel power plantsIntegrated coal gasification combined cycle (IGCC)Pulverized coal combustion (PC)Natural gas combined cycle (NGCC)
• Other large industrial sources of CO2 such as:Refineries, fuel processing, and petrochemical plantsHydrogen and ammonia production plantsPulp and paper plantsCement plants
– Focus of this talk is on power plants –
E.S. Rubin, Carnegie Mellon
COCO22 Capture Options for Power PlantsCapture Options for Power Plants
Source: IPCC SRCCS, 2005
Reformer+CO2 Sep
Air Separation
CO2Separation
Coal Gas
Biomass
CO2Compression& Dehydration
Power & Heat
Power & Heat
Power & Heat
N2
N2 O2
O2
H2
N2O2
CO2
CO2
CO2
Air
Post combustion
Pre combustion
Oxyfuel
Air
Air
Coal Gas
Biomass
C l
Gasification
Gas, Oil
Coal Gas
Biomass
Air/O2Steam
Air/O2
Reformer+CO2 SepReformer+CO2 Sep
Air Separation
CO2Separation
CO2Separation
Coal Gas
Biomass
CO2Compression& Dehydration
Power & HeatPower & Heat
Power & HeatPower & Heat
Power & Heat
N2
N2 O2
O2
H2
N2O2
CO2
CO2
CO2
Air
Post combustion
Pre combustion
Oxyfuel
Air
Air
Coal Gas
Biomass
C l
GasificationGasification
Gas, Oil
Coal Gas
Biomass
Air/O2Steam
Air/O2
Coal
E.S. Rubin, Carnegie Mellon
Pulverized CoalPulverized Coal--Fired Power Plant Fired Power Plant with Postwith Post--Combustion COCombustion CO22 CaptureCapture
E.S. Rubin, Carnegie Mellon
Schematic of Amine Capture SystemSchematic of Amine Capture System
Flue Gas In
Sorbent makeup
Absorber
Captured CO2
Regenerated Sorbent
CO2 CO2
Regeneratorη
Heat
Flue Gas Out
Amine Sorbent
Typical CO2 Removal Efficiency ≈ 90%
Examples of Post-CombustionCO2 Capture at Coal-Fired Plants
Warrior Run Power Plant(Cumberland, Maryland, USA)
(Sou
rce:
(IEA
GH
G)
Shady Point Power Plant(Panama, Oklahoma, USA)
(Sou
rce:
ABB
Lum
mus
)
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Schematic of PC Plant w/ CCS(Post-combustion amine system)
E.S. Rubin, Carnegie Mellon
Natural Gas Combined Cycle Plant Natural Gas Combined Cycle Plant with Postwith Post--Combustion COCombustion CO22 CaptureCapture
Examples of Post-CombustionCO2 Capture at Gas-Fired Plants
Petronas Urea Plant Flue Gas(Keda, Malaysia)
(Sou
rce:
Mits
ubis
hi H
eavy
Indu
stri
es)
E.S. Rubin, Carnegie Mellon
Bellingham Cogeneration Plant(Bellingham, Massachusetts, USA)
(Sou
rce:
Sue
z Ene
rgy
Gen
erat
ion)
)
E.S. Rubin, Carnegie Mellon
Integrated Coal Gasification Combined Integrated Coal Gasification Combined Cycle Plant w/ PreCycle Plant w/ Pre--Combustion CaptureCombustion Capture
GE-quench O2-blown
E.S. Rubin, Carnegie Mellon
WaterWater--Gas Shift Reactor Schematic Gas Shift Reactor Schematic
High Temp
ReactorSyngas
(CO + H2)
SteamLow Temp
ReactorShifted Syngas
(CO2 + H2)
CO + H2O CO2 + H2
E.S. Rubin, Carnegie Mellon
Selexol COSelexol CO22 Capture SchematicCapture Schematic
SUMP
Shifted Syngas
Rich Solvent
Recycle Gas
CO2
PumpCoolerLean
Solvent
H2 Fuel Gas(to Power Block)
Absorber
COMP1
COMP3
COMP2
FLASH1 FLASH2 FLASH3
TURB1 TURB2
CO2 CO2
CO2 to Storage
Examples of Pre-CombustionCO2 Capture Systems
Coal Gasification to Produce SNG(Beulah, North Dakota, USA)
(Sou
rce:
Dak
ota
Gas
ifica
tion
Petcoke Gasification to Produce H2(Coffeyville, Kansas, USA)
(Sou
rce:
Che
vron
-Tex
aco)
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Integrated Coal Gasification Combined Cycle (IGCC) Plant
Polk Power Station, Tampa, Florida(250 MW, no CO2 capture)
Source: TECO, 2004
E.S. Rubin, Carnegie Mellon
Schematic of IGCC w/ CO2 Capture
E.S. Rubin, Carnegie Mellon
Pulverized CoalPulverized Coal--Fired Power Plant Fired Power Plant with Oxyfuel Combustion Capturewith Oxyfuel Combustion Capture
CoalDistillation
water
CO2
Air
H2O
O2
SteamTurbine
Generator
Electricity
Steam
PC Boiler CO2compression
Air Separation
Unit
CO2 to recycle
to atmosphere
Air PollutionControls
(ESP, FGD)
CO2CO2CoalDistillation
water
CO2
Air
H2O
O2
SteamTurbine
Generator
Electricity
Steam
PC Boiler CO2compression
Air Separation
Unit
CO2 to recycle
to atmosphere
Air PollutionControls
(ESP, FGD)
CO2CO2 to storage
to atmosphere
CoalDistillation
water
CO2
Air
H2O
O2
SteamTurbine
Generator
Electricity
Steam
PC Boiler CO2compression
Air Separation
Unit
CO2 to recycle
to atmosphere
Air PollutionControls
(ESP, FGD)
CO2CO2CoalDistillation
water
CO2
Air
H2O
O2
SteamTurbine
Generator
Electricity
Steam
PC Boiler CO2compression
Air Separation
Unit
CO2 to recycle
to atmosphere
Air PollutionControls
(ESP, FGD)
CO2CO2 to storageCoalDistillation
water
CO2
Air
H2O
O2
SteamTurbine
Generator
Electricity
Steam
PC Boiler CO2compression
Air Separation
Unit
CO2 to recycle
to atmosphere
Air PollutionControls
(ESP, FGD)
CO2CO2CoalDistillation
water
CO2
Air
H2O
O2
SteamTurbine
Generator
Electricity
Steam
PC Boiler CO2compression
Air Separation
Unit
CO2 to recycle
to atmosphere
Air PollutionControls
(ESP, FGD)
CO2CO2 to storage
to atmosphere
E.S. Rubin, Carnegie Mellon
The Vattenfall30 MWth Oxy-CoalPilot Boiler withCO2 capture atSchwarze Pumpe(Germany), starting mid-2008
Pilot here
The Vattenfall30 MWth Oxy-CoalPilot Boiler withCO2 capture atSchwarze Pumpe(Germany), starting mid-2008
Source: Vattenfall, 2006
E.S. Rubin, Carnegie Mellon
Summary of Capture StatusSummary of Capture Status
• Several existing applications of CO2 capture at scales small compared to a modern power plant, but
• Several new large-scale projects proposed in different countries to demonstrate pre-combustion, post-combustion and oxyfuel fuel combustion over the coming decade using a variety of fuels (coal, gas, liquids) in power plant and related industrial applications
How effective are current How effective are current COCO22 capture systems?capture systems?
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Illustrative COIllustrative CO22 Emission Rates for Emission Rates for New Power Plants New Power Plants (kg CO(kg CO22/MWh)/MWh)
Typical emission reduction is 85-86%
based on CO2avoided
(for ~90% capture)
0100200300400500600700800900
NGCCIGCC
Without CCS
SCPC
With CCS
SCPC NGCCIGCC
CO
2 Em
itted
(kg
/MW
h)
E.S. Rubin, Carnegie Mellon
Is There an Optimal Capture Efficiency?Is There an Optimal Capture Efficiency?
• Our studies show that the most cost-effective level of CO2 capture (minimum cost per ton of CO2 avoided) occurs at removal efficiencies of about 85%–90% for both PC and IGCC plants using current technology
• Optimal level varies slightly with plant size and other factors that affect the number of absorber and compressor trains required for CO2 capture and compression
What is the impact on What is the impact on other plant emissions ? other plant emissions ?
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Importance of the CCSImportance of the CCS“Energy Penalty”“Energy Penalty”
• CCS energy requirements are defined here as the increase in fuel energy input per unit of net electrical output (relative to a similar plant without capture)
• This directly affects the plant-level resource requirements and emissions per MWh of:
Fuel and reagent useAir pollutant emissions Solid and liquid wastesUpstream (life cycle) impacts
• Additional energy/MWh for representative plants: PC = 31%; IGCC = 16%; NGCC = 17%
E.S. Rubin, Carnegie Mellon
Case Study Increases in Case Study Increases in Fuel and Reagent ConsumptionFuel and Reagent Consumption
Increase in Ammonia Consumption
0.00
0.10
0.20
0.30
PC IGCC NGCC
kg ammonia / MWh
Increases in Coal and Natural Gas Consumption
0
20
40
60
80
100
PC IGCC NGCC
kg fuel / MWh
Increase in Limestone Consumption
0
2
4
6
8
10
PC IGCC NGCC
kg limestone / MWh
Source: Rubin, et.al, 2005
E.S. Rubin, Carnegie Mellon
Case Study Increases inCase Study Increases inSolid Wastes & Plant ByproductsSolid Wastes & Plant Byproducts
Increases in Ash or Slag Residues
0
2
4
6
8
10
PC IGCC NGCC
kg ash or slag / MWh
Increases in Desulfurization System Residues
02468
101214
PC IGCC NGCC
kg DeSOx residues / kWh
Source: Rubin, et.al, 2005
E.S. Rubin, Carnegie Mellon
Case Study Increases inCase Study Increases inAir Emission RatesAir Emission Rates
Increase in NOx Emission Rate
0.00
0.05
0.10
0.15
0.20
PC IGCC NGCC
kg NOx / MWh
Increase in SO2 Emission Rate
-0.30-0.25-0.20-0.15-0.10-0.050.000.050.10
PC IGCC NGCC
kg SO2 / MWh
IGCC
Increase in NH3 Emission Rates
0.00
0.05
0.10
0.15
0.20
PC IGCC NGCC
kg NH3 / MWh
Source: Rubin, et.al, 2005
E.S. Rubin, Carnegie Mellon
Case Study Impacts of CCS on Plant Case Study Impacts of CCS on Plant Resource Use and Emission RatesResource Use and Emission Rates
PC IGCC NGCC Capture Plant Parameter Rate Increase Rate Increase Rate Increase
Resource Consumption (All values in kg/MWh) Fuel 390 93 364 50 156 23
Limestone 27.5 6.8 - - - - Ammonia 0.80 0.19 - - - -
CCS Reagents 2.76 2.76 0.005 0.005 0.80 0.80 Solid Wastes/ Byproduct
Ash/slag 28.1 6.7 34.2 4.7 - - FGD residues 49.6 12.2 - - - -
Sulfur - - 7.7 1.2 - - Spent CCS sorbent 4.05 4.05 0.005 0.005 0.94 0.94
Atmospheric Emissions CO2 107 –704 97 –720 43 –342 SOx
0.001 – 0.29 0.011 –0.13 - - NOx 0.77 0.18 0.10 0.01 0.11 0.02 NH3 0.23 0.22 - - 0.002 0.002
(Capture plant rate and increase over reference plant rate, kg/M(Capture plant rate and increase over reference plant rate, kg/MWh)Wh)
E.S. Rubin, Carnegie Mellon
Reducing Environmental ImpactsReducing Environmental Impacts
• New or improved power generation and CO2capture technologies promise to reduce CCS impacts by:
Improving overall plant efficiencyReducing CCS energy requirementsIncreasing CO2 capture efficiencyMaximizing pollutant co-capture & disposal
More on this a little later
How much does CCS cost? How much does CCS cost?
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Many Factors Affect Reported Many Factors Affect Reported Costs of COCosts of CO22 Capture & StorageCapture & Storage
• Choice of CCS Technology• Process Design and Operating Variables• Economic and Financial Parameters• Choice of System Boundaries; e.g.,
One facility vs. multi-plant system (regional, national, global)GHG gases considered (CO2 only vs. all GHGs)Power plant only vs. partial or complete life cycle
• Time Frame of InterestCurrent technology vs. future (improved) systemsConsideration of technological “learning”
E.S. Rubin, Carnegie Mellon
Different Measures of CostDifferent Measures of Cost
($/MWh)ccs – ($/MWh)reference
(CO2/MWh)ref – (CO2/MWh)ccs
• Cost of CO2 Avoided ($/ton CO2 avoided)
=
• Cost of CO2 Abated ($/ton CO2 reduced)($ NPV)ccs – ($ NPV)reference
(CO2)ref – (CO2)ccs=
• Cost of Electricity ($/MWh)(TCC)(FCF) + FOM
(CF)(8760)(MW) + VOM + (HR)(FC)=
E.S. Rubin, Carnegie Mellon
Ten Ways to Reduce the Estimated Cost Ten Ways to Reduce the Estimated Cost of COof CO22 AbatementAbatement
10. Assume high power plant efficiency 9. Assume high-quality fuel properties8. Assume low fuel costs7. Assume EOR credits for CO2 storage6. Omit certain capital costs5. Report $/ton CO2 based on short tons4. Assume long plant lifetime3. Assume low interest rate (discount rate)2. Assume high plant utilization (capacity factor)1. Assume all of the above !
. . . and we have not yet considered the CCS technology!
E.S. Rubin, Carnegie Mellon
Important RemindersImportant Reminders
• No one has yet built and operated a CO2capture and sequestration system at a large-scale (e.g., 500 MW) power plant
• Hence, all the costs we’re about to see are projections based on other applications; the “true” costs are not yet known
• In the last few years plant construction costs have escalated considerably (~30% from 2002 to 2006); current (2007) costs are thus higher than those reported in recent studies
E.S. Rubin, Carnegie Mellon
Estimated Cost and Emissions of Estimated Cost and Emissions of Power Plants with and without CCSPower Plants with and without CCS**
0
20
40
60
80
100
120
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Cos
t of E
lect
ricity
($ /
MW
h)
CO2 Emission Rate (tonnes / MWh)
SCPC
IGCC
New Coal
Plants
* 2002 costs for bituminous coals; gas price ≈ $3–6/GJ; 90% capture; aquifer storage
Current Coal
Plants
PCNGCC
Natural Gas
Plants PlantswithCCS
SCPC
IGCC
NG
CC
E.S. Rubin, Carnegie Mellon
Representative CCS Costs for New Representative CCS Costs for New Power Plants Using Current TechnologyPower Plants Using Current Technology
Incremental Cost of CCS Relative to Similar Plant
without CCS
Natural Gas Combined Cycle Plant
Supercritical Pulverized Coal Plant
Integrated Gasification Combined Cycle Plant
Increase in plant capital cost for capture & compression ~76% ~63% ~37%
Increase in levelized COE (capture & compression only) ~46% ~57% ~33%
Added cost of CCS with aquifer storage ($/MWh) 10–30 20–50 10–30
Added cost of CCS with EOR storage ($/MWh) 10–20 10–30 0–10
Source: IPCC, 2005
Variability is due mainly to differences in site-specific factors. Added cost to consumers will depend on extent of CCS plants
in the overall power generation mix over time
E.S. Rubin, Carnegie Mellon
Cost of COCost of CO22 Avoided ($/tCOAvoided ($/tCO22) ) (Based on Current Technology)(Based on Current Technology)
Cost of CO2 Avoided Relative to Similar Plant
without CCS
Natural Gas Combined Cycle Plant
SupercriticalPulverized Coal Plant
Integrated Gasification Combined Cycle Plant
Capture & compress only 35–75 30–50 15–35
+ Saline aquifer storage 40–90 30–70 15–55
+ EOR storage (credits) 20–70 10–45 (-5)–30
Levelized cost in 2002 US$ per tonne CO2 avoided
Source: IPCC, 2005
Different mixes of plants with and without CCS will have other avoidance costs; site-specific context is very important
E.S. Rubin, Carnegie Mellon
Effects of Coal Quality on Cost of Effects of Coal Quality on Cost of Electricity for PC and IGCC w/CCS Electricity for PC and IGCC w/CCS
(2005 $/MWh; dashed lines based on constant $/GJ for all coals)(2005 $/MWh; dashed lines based on constant $/GJ for all coals)
0
20
40
60
80
100
120
140
Pittsburgh #8 Illinois #6 Wyoming PRB ND Lignite
Coal Type
Cos
t of E
lect
rici
ty ($
/MW
h)
IGCC-CCS PC-CCS
0
20
40
60
80
100
120
140
Pittsburgh #8 Illinois #6 Wyoming PRB ND Lignite
Coal Type
Cos
t of E
lect
rici
ty ($
/MW
h)
IGCC-CCS PC-CCS
0
20
40
60
80
100
120
140
Pittsburgh #8 Illinois #6 Wyoming PRB ND Lignite
Coal Type
Cos
t of E
lect
rici
ty ($
/MW
h)
IGCC-CCS PC-CCS
All plants ~500 MW(net); 75% CF; Aquifer storage;IGCC based on GE quench; PC=supercritical
Detailed Detailed results and results and breakdown breakdown of costs for of costs for
different different systems are systems are available in available in published published papers and papers and
reports reports
$/kW $/MWh $/MWhNGCC Plant1 916 100 38.5 100 59.1 100 GTCC (power block) 660 72 2.2 6 17.1 29 CO2 capture (amine system) 218 24 2.4 6 7.3 12 CO2 compression 38 4 0.2 0 1.0 2 Fuel cost 0 0 33.6 87 33.6 57
PC Plant2 1,962 100 29.3 100 73.4 100 PC Boiler/turbine-generator area 1,282 65 5.7 19 34.5 47 AP controls (SCR, ESP, FGD) 241 12 4.1 14 9.5 13 CO2 capture (amine system) 353 18 7.2 25 15.2 21 CO2 compression 86 4 0.4 1 2.3 3 Fuel cost 0 0 11.9 41 11.9 16
IGCC Plant3 1,831 100 21.3 100 62.6 100 Air separation unit 323 18 1.7 8 8.9 14 Gasifier area 494 27 3.7 17 14.8 24 Sulfur removal/recovery 110 6 0.6 3 3.1 5 CO2 capture (WGS/Selexol) 246 13 1.6 7 7.1 11 CO2 compression 42 2 0.3 1 1.2 2 GTCC (power block) 616 34 2.0 9 15.8 25 Fuel cost 0 0 11.6 54 11.6 19
Oxyfuel Plant4 2,417 100 24.4 100 78.9 100 Air separation unit 779 32 3.1 13 20.6 26 PC boiler/turbine generator area 1,280 53 5.6 23 34.4 44 AP controls (ESP, FGD) 132 5 2.7 11 5.7 7 CO2 distillation 160 7 1.4 6 5.0 6 CO2 compression 66 3 0.5 2 1.9 2 Fuel cost 0 0 11.2 46 11.2 14
Plant Type & TechnologyTotal COE6,7
Total Plant Costs ($2002)
% Total % TotalTotal O&M Cost5
% TotalCapital Cost
Notes: 1. NGCC plant = 432 MW (net); 517 MW (gross); two 7FA gas turbines; gas price = 4.0 $/GJ; 2. PC plant = 500 MW (net); 719 MW (gross); supercritical boiler; Pittsburgh #8 coal; price = 1.0 $/GJ; 3. IGCC plant = 490 MW (net); 594 MW (gross); 3 GE gasifiers + two 7FA gas turbines; Pgh #8 coal; price = 1.0 $/GJ; 4. Oxyfuel plant = 500 MW (net); 709 MW (gross); supercritical boiler; Pittsburgh #8 coal; price = 1.0 $/GJ; 5. Based on levelized capacity factor of 75% for all plants.; 6. COE is the levelized cost of electricity ; 7. Based on fixed charge factor of 0.148 for all plants; 8. The cost of reference plants with similar net output and no CO2 capture are: NGCC = $563/kW, $43.3/MWh; PC= $1229/kW, $44.9/MWh; IGCC = $1327/kW, $46.8/MWh.
What is the outlook for improved What is the outlook for improved capture technology? capture technology?
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Two Approaches to Estimating Two Approaches to Estimating Future Technology CostsFuture Technology Costs
• Method 1: Engineering-Economic Analysis
A “bottom up” approach based on engineering process models, informed by judgments regarding potential improvements in key process parameters
E.S. Rubin, Carnegie Mellon
Latest Projections by DOE/NETLLatest Projections by DOE/NETL
3128
19
12 10
5 5
0
5
10
15
20
25
30
35
40
A B C D E F G
Latest Analyses for IGCC
7.13(c/kWh)
7.01(c/kWh)
6.14(c/kWh) 6.03
(c/kWh)
5.75(c/kWh)
5.75(c/kWh)
6.52(c/kWh)
SelexolSelexolAdvanced
SelexolAdvanced
Selexol
AdvancedSelexol w/co-Sequestration
AdvancedSelexol w/co-Sequestration
AdvancedSelexol w/ITM
& co-Sequestration
AdvancedSelexol w/ITM
& co-Sequestration
WGS Membrane& Co-Sequestration
WGS Membrane& Co-Sequestration
WGS Membrane w/ITM & Co-
Sequestration
WGS Membrane w/ITM & Co-
Sequestration
Chemical Looping& Co-
Sequestration
Chemical Looping& Co-
Sequestration
Perc
ent I
ncre
ase
in C
OE
01020304050607080
70 69
5550 52
45
22
A B C D E F G
`
8.77(c/kWh)
8.72(c/kWh)
8.00(c/kWh)
7.74(c/kWh)
7.48(c/kWh)
7.84(c/kWh)
Latest Analyses for PC Plants
Perc
ent I
ncre
ase
in C
OE
SC w/AmineScrubbingSC w/AmineScrubbing
SC w/AmmoniaCO2 ScrubbingSC w/AmmoniaCO2 Scrubbing
SC w/EconamineScrubbingSC w/EconamineScrubbing SC w/Multipollutant
Ammonia Scrubbing(Byproduct Credit)
SC w/MultipollutantAmmonia Scrubbing(Byproduct Credit)
USC w/AmineScrubbingUSC w/AmineScrubbing USC w/Advanced
Amine ScrubbingUSC w/AdvancedAmine Scrubbing
6.30 (c/kWh)
RTI RegenerableSorbentRTI RegenerableSorbent
50
3326
21
0
10
20
30
40
50
60
A B C D
`
6.97(c/kWh)
6.62(c/kWh)
6.35(c/kWh)
Latest Analyses for Oxy-Combustion
Perc
ent I
ncre
ase
in C
OE Advanced
Subcritical Oxyfuel(Cryogenic ASU)
AdvancedSubcritical Oxyfuel(Cryogenic ASU)
AdvancedSupercritical Oxyfuel
(Cryogenic ASU)
AdvancedSupercritical Oxyfuel
(Cryogenic ASU)Advanced
Supercritical Oxyfuel(ITM O2)
Advanced Supercritical
Oxyfuel(ITM O2)
7.86(c/kWh)
Current StateSupercritical Oxyfuel
(Cryogenic ASU)
Current StateSupercritical Oxyfuel
(Cryogenic ASU)
Source: DOE Office of Fossil Energy, 2006
E.S. Rubin, Carnegie Mellon
Two Approaches to Estimating Two Approaches to Estimating Future Technology CostsFuture Technology Costs
• Method 2: Use of Historical Experience Curves
A “top down” approach based on applications of mathematical “learning curves” or “experience curves” that reflect historical trends for analogous technologies or systems
E.S. Rubin, Carnegie Mellon
Estimated Learning Rate for CCS PlantsEstimated Learning Rate for CCS Plants(Based on 100 GW of cumulative CCS capacity for each system)(Based on 100 GW of cumulative CCS capacity for each system)
0
2
4
6
8
10
Pow
er P
lant
Lea
rnin
g R
ate
(%)
NGCC PC IGCC Oxyfuel
COST OF ELECTRICITY
0
5
10
15
20
25
30
Perc
ent R
educ
tion
in C
OE
NGCC PC IGCC Oxyfuel
% REDUCTION
Source: IEA GHG, 2006
What are the key needs to What are the key needs to develop improved technology? develop improved technology?
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Key NeedsKey Needs
• Deployment, deployment, deployment !
• Sustained (and increased) R&D support
• Resolution of current legal and institutional uncertainties surrounding geological sequestration
Regulatory requirements (esp.for deep injection)Liabilities (near-term and long-term)Financing and insurance requirementsEmissions allowance & trading rules for CCS projects
E.S. Rubin, Carnegie Mellon
Concluding CommentsConcluding Comments
• Absent a climate policy with sufficiently stringent limits on CO2 emissions, there is little or no incentive to develop and deploy CO2 capture and storage technologies
• Market-based policies aimed broadly at reducing CO2emissions (e.g., cap-and-trade) are not likely to stimulate CCS until carbon price exceeds roughly $100/tC ($27/tCO2)
• Policies aimed specifically at fossil fueled plants (e.g., performance and/or portfolio standards) can accelerate CCS deployment and innovation, especially in conjunction with incentives for early actors
• Analysis of options is underway by a number of parties; the ACT Work Group can contribute significantly to this effort