EPRI IGCC Study Cost and Performance … · Agenda • Recent Economic Trends • EPRI IGCC Study...
Transcript of EPRI IGCC Study Cost and Performance … · Agenda • Recent Economic Trends • EPRI IGCC Study...
EPRI IGCC Study Cost and Performance ResultsPerformance Results
George Booras ([email protected])Neville Holt ([email protected])Ron Schoff (rschoff@epri com)Ron Schoff ([email protected])
2008 Gasification Technologies ConferenceWashington, DCOctober 8, 2008
Agenda
• Recent Economic Trends• EPRI IGCC Study Status Report
– Shell IGCC Results• EPRI CPS Energy Study Results Comparison• EPRI CPS Energy Study Results Comparison• Conclusions
2© 2008 Electric Power Research Institute, Inc. All rights reserved.
Challenges of Estimating Cost & Performance
• Cost and performance can vary significantly due to:– Design basis and plant battery limit assumptions– Assumed maturity of technology– Cost estimating approachCost estimating approach
• Methodology and design assumptions are critical– Input from licensors needed to validate process models– Requires multiple iterations for optimum results
• Rapidly escalating costs makes comparisons difficultT i l t i d d ’t fl t th k t lit– Typical cost indexes don’t reflect the market reality
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Cost Escalation ImpactsProjected Growth in Electricityj y
• Global competition for plants 2000
3150 GWe
for plants• US growth only
5% of Worldwide f t 2030
1500
000
ons
(GW
e)
RequiredPlanned
from now to 2030• Focus on demand
reduction via 1000
ower
Add
itio
energy efficiency• Competition from
Renewables, 0
500
Gro
ss P
o
,Nuclear & improving PC w/CCS
0
United
States
urop
ean U
nion
China
India
Russia
Worldwide
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Eur
Recent Economic TrendsFrom FERC “Increasing Cost in Electric Markets”*
Natural Gas sPrimary Construction Costs
Coal sSecondary Construction Costs
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*June 19, 2008: U.S. Federal Energy Regulatory Commission
Now Is (Very) DifferentFrom FERC “Increasing Cost in Electric Markets”*
Estimated Cost of New Generation
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*June 19, 2008: U.S. Federal Energy Regulatory Commission
EPRI CoalFleet Technology Study Matrix
Technology / Fuel Petroleum Coke
Pittsburgh #8
Illinois #6
Utah Bituminous
PRB Texas & ND Lignites
Study Location Midwest Midwest Utah Midwest & West
Minemouth
GE Radiant/Quench Phase ? Phase I DOE Phase ?ConocoPhillips E Gas™ Phase ? Phase I Phase I & Phase ? Phase IConocoPhillips E-Gas™ Phase ? Phase I Phase I &
DOE Phase ? Phase I
Shell Phase ? Phase I DOE Phase ? Phase I Phase ?Siemens Phase ? Phase I Phase ? Phase ? Phase I Phase ?KBR Transport Phase I Phase ?
IGC
C
KBR Transport Phase I Phase ?Supercritical X X DOE X X XUSC Phase ? Phase I DOE Phase ? Phase I Phase ?SC CFBC X X X X X X
PC
1. All cases to be performed in power only and CO2 capture mode2. 1 PRB Case to be done at elevation, including GT power augmentation
X = Cases not yet performed Green = Phase I Cases Red = Lack of technology development
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3. Ill #6 cases to provide cost comparison to NETL study and Retrofit vs. Greenfield
Gasification Vendor InteractionStatus Report
• Shell – Extensive design and cost iterations with FWI• Siemens – Design iterations with FWI nearly complete;
cost phase in progress; also provided GT data• Southern/KBR – Design iterations complete; Cost phaseSouthern/KBR Design iterations complete; Cost phase
iterations under review• ConocoPhillips – Data submittal underway• General Electric – Design iterations complete; cost
phase iterations complete (see comparison in GE presentation); also provided GT datapresentation); also provided GT data
• UOP – Provided extensive details on Selexol unit design• Haldor Topsoe – Provided WGS catalyst data
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IGCC with CO2 CaptureProcess Flow Diagram
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Shell Case StudiesStatus Report
• Shell participated in design and approved all gasification island performance and cost dataisland performance and cost data
• Design options studied:– Coal: Pittsburgh #8 vs. Powder River BasinCoal: Pittsburgh #8 vs. Powder River Basin– Heat Recovery: Syngas cooler vs. Water Quench– Gasifier Design: 2 Gasifiers/2 GT vs. 2/3
• Engineering is complete• Cost Estimation is complete
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Buggenum (Netherlands)
Shell Syngas Cooler CasesPRB Coal, Retrofit CO2 Capture with Moderate Pre-Investment, UDBS Environmental Profile #2/3
Case 12N C t
Case 13F ll C t
UDBS Environmental Profile #2/3
No Capture Full CaptureGas Turbine (MWe) 464.0 464.0Steam Turbine (MWe) 235.1 213.2Total Gross Power (MWe) 699.1 677.2 Δ = -3% Total Gross Power (MWe) 699.1 677.2Total Auxiliary Load (MWe) 111.0 191.1
Net Plant Power Output (MWe) 588.1 486.1Net Plant Heat Rate, HHV (Btu/kWh) 8,530 10,980, ,
Net Plant Efficiency, HHV 40.0% 31.1%Coal Flow Rate (Ton/day) 7,220 7,680
CO2 Emissions (lb/MW gross) 1,490 20786% Capture
8.9 point drop
Δ = +6%
CO2 Emissions (lb/MW net) 1,771 28486% Capture
Notes: Results are Subject to Change
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Overview of CPS Shell-Based IGCC Study
• In 2006 CPS Energy funded a study of IGCC with PRB at T it t f ttl t ith i t la Texas site as part of a settlement with environmental
groups who opposed plans for construction of the 750 MW subcritical Spruce 2 PC plantp p– Burns & McDonnell and EPRI performed the study
• No input from the gasifier or gas turbine vendors• Input from UOP on Selexol design, though no iterations
for optimization took place and initial assumptions were overly strictoverly strict
• CCS was retrofitted onto the base plant design, which included no pre-investment or consideration for CCS
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• Impact of CCS retrofit excessively inefficient and costly
CPS Study Methodology
• EPRI developed heat and material balances for the Shell gasification island based on Shell’s 2004 GTC papergasification island based on Shell’s 2004 GTC paper
• Capital costs for gasification island were based on published Shell papersp p p– Burns & McDonnell adjusted capital costs to Texas coastal
location and escalated to 2006 dollars• Burns & McDonnell developed overall performance and• Burns & McDonnell developed overall performance and
cost estimates, including:– Coal/coke handling and preparation– Gas cleanup and sulfur recovery– Combined cycle power generation– Other balance-of-plant facilities
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Design Basis Comparison
• 59°F ambient temperature • 73°F ambient temperatureEPRI-FWI IGCC Study (2008) CPS-EPRI-B&M Study (2006)
• 59 F ambient temperature• Moderate Pre-investment• Coal drying with RWE WTA
• 73 F ambient temperature• No pre-investment• Coal drying with syngas
• No GT air conditioning• CO2 capture: 86%• CO2 spec: <100 ppmv S
• No GT air conditioning• CO2 capture: 90%• CO2 spec: 25 ppmv S2 p pp
• Level site• Included SCR• Tail gas recycle
2 p pp• Assumed 10 ft cut/fill for site• No SCR• Tail gas treatment• Tail gas recycle
• No extra infrastructure costs were includedC t id 2008 $
• Tail gas treatment• Included gas and water pipelines,
rail siding, switchyardC t id 2006 $
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• Costs: mid-2008 $ • Costs: mid-2006 $
Power Output and Heat Rate Comparisons
1,000
1,100 14,000EPRI-FWI Study CPS-EPRI-B&M Study
800
900
1,000
e)
10,000
12,000
Wh)
600
700
800
Our
put (
MW
e
6 000
8,000
at ra
te (B
tu/k
W
16% 22%
400
500
600
Pow
er
4,000
6,000
Net
Hea28%
34%
200
300
400
0
2,000
Gross PowerNet Power
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Notes: 1. EPRI study at 59°F ambient; CPS at 73°F2. CPS includes no pre-investment, therefore GT not at full output w/CCS
200Base Case CCS Case Base Case CCS Case
0Heat Rate
Capital Cost Comparisons
5,000
4,000
4,500
5,000
2 500
3,000
3,500
BaseCCSt C
ost,
$/kW
1,500
2,000
2,500 CCS
Tota
l Pla
nt
500
1,000
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0EPRI-FWI Study CPS-EPRI-B&M
Note: CPS Costs escalated to 2008 using CERA Downstream Capital Cost Index (DCCI)
IGCC Case StudiesConcluding Remarks
• Design choices may have a significant impact on the ffi i f IGCC l t ith CCS d th i t defficiency of IGCC plants with CCS and the associated
economics• Participation of technology suppliers is critical toParticipation of technology suppliers is critical to
understanding performance and cost in this volatile time• Syngas properties and CO2 purity requirements have a
di d b i l i id l ldirect and substantial impact on acid gas removal plant design
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18© 2008 Electric Power Research Institute, Inc. All rights reserved.Image courtesy of Image courtesy of NASA Visible EarthNASA Visible Earth