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Update on Clean Coal Technologies and CO2 Capture


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Title: Update on Clean Coal Technologies and CO2 Capture

Update on Clean Coal Technologies and CO2
Capture Storage
  • For Oregon Public Utility Commission
  • Salem ,OR - June 27, 2007
  • Neville Holt EPRI Technical Fellow Advanced
    Coal Generation Technology

Clean Coal Technologies (CCT) and CO2 Capture and
Storage (CCS) - Presentation Outline
  • Overview Options for Response to Global Climate
  • Clean Coal Technology (CCT) Options
  • EPRI CoalFleet Program
  • PC Post Combustion Removal Status, Chilled
  • Oxyfuel Status, SaskPower,
  • IGCC Status, Capture Technology,
  • Economic Studies DOE, EPRI - New Plants with and
    without Capture
  • IGCC/PC EPRI Study adding Capture to new plants
    designed without Capture
  • Effect of Capital Cost increases and Carbon (CO2)
    cost on COE and Strategic selection of power
    generation technologies
  • Summary

Regulatory Uncertainty on CO2 Emissions
  • Kyoto Signatory Countries post 2012. EU ETS
    Phase 2. UK .
  • US proposed Federal legislation -
    McCain/Lieberman, Bingaman, Sanders/Boxer,
    Feinstein/Carper, Kerry/Snowe
  • US Regional Initiatives
  • Western Regional Climate Action (WA,OR,CA,AZ, and
    NM). Western Governors Association (WGA)
  • RGGI East Coast Regional GHG Initiative (10 NE
  • Powering the Plains (ND,SD,IA,MN,WI, Manitoba)
  • California Governors Executive Order GHG
    targets 2010 cut to 2000 (-11), 2020 cut to 1990
    (-30), 2050 80 below 1990.
  • New long term base load power or renewal
    (gt5years) commitments shall have CO2 emissions no
    greater than NGCC (established as lt1100 lbs/MWh).
  • Oregon Washington have enacted similar
  • Liability of CO2 injection into geological
    formations ?

Power Company Carbon Management Options
Options for CO2 Response(The Stabilization Wedge
  • Conservation (Yes - but Rest of the World?)
  • Renewables (Yes - but not enough)
  • Nuclear (Ultimately Yes but implies wide
  • Adaptation (Probably Yes we always do)
  • Switch from Coal to Natural Gas (Maybe but not
    enough NG)
  • CO2 Capture Sequestration (CCS) (Maybe but site
    specific costly - Liability for the
    Sequestered CO2?)
  • Notes
  • US Coal Power Plants emit gt 2 billion metric
    tons of CO2/yr (36 of US and 8
    of World CO2 emissions).
  • 1 billion metric tons/yr 25 million bpd of
    supercritical CO2
  • Effort Required for CCS Slice- World-wide
    build or replace 8 GW of Coal Power plants with
    CCS every year and maintain them until 2054

CO2 Capture in Coal Power Systems
New Technology Deployment Curve for Coal
Not All Technologies at the Same Level of
EPRI Programs 2007ff
  • P 66 CoalFleet for Tomorrow Future Coal Options

    Focus on Deployment of New Plants, Designs for
    Capture Readiness and Capture
  • - 66 A Economic and Technical Overview
  • - 66 B Gasification - IGCC and Co-production
    (Hydrogen, SNG, F-T Diesel etc)
  • - 66 C Combustion - USC PC, Advanced materials,
    CFBC, OxyFuel
  • P 103 CO2 Capture Storage
  • Focus on Sequestration and Existing Plants
  • - Participation in US Regional Partnerships, IEA
  • - Capture focus Existing Plants
  • - Chilled Ammonia (ABS) 5 MW Pilot Plant

EPRIs CoalFleet forTomorrow Program
  • Build an industry-led program toaccelerate the
    deployment ofadvanced coal-based power
    plantsuse lessons learned to minimize risk

    address Capture Readiness
  • Employ learning by doing approach generalize
    actual deployment projects (50 60 Hz) to
    create design guides
  • Augment ongoing RDD to speed market introduction
    of improved designs and materials lead industry
    collaborative projects
  • Deliver benefits of standardization to IGCC
    (integration gasification combined cycle), USC PC
    (ultra-supercritical pulverized coal), and SC
    CFBC (supercritical circulating fluidized-bed
  • Lower costs, especially with CO2 capture
  • Higher reliability
  • Near-zero SOX, NOX, PM, and Hg emissions
  • Shorter project schedule

Further information availableat
CoalFleet Participants Span 5 Continents gt60 of
U.S. Coal-Based Generation, Large European
Generators,Major OEMs (50 60 Hz) and EPCs,
  • AES
  • Alliant
  • Alstom Power
  • Ameren
  • American Electric Power
  • Arkansas Electric Coop
  • Austin Energy
  • Babcock Wilcox
  • Bechtel Corp.
  • BP
  • California Energy Commission
  • CPS Energy
  • ConocoPhillips Technology
  • CSX Corporation
  • Dairyland Power Coop
  • Doosan Heavy Industries
  • Duke Energy Corp
  • Dynegy
  • East Kentucky Power Coop
  • EdF
  • Edison International
  • ENEL
  • Entergy
  • E.ON
  • Exelon Corp.
  • FirstEnergy Service
  • GE Energy
  • Great River Energy

CoalFleet Participants Span 5 Continents (contd)
  • Golden Valley Electrical Association
  • Hitachi
  • Hoosier Energy
  • Jacksonville Electric Authority
  • Kansas City Power Light
  • Lincoln Electric
  • MHI
  • Minnesota Power
  • Nebraska Public Power District
  • New York Power Authority
  • PacifiCorp
  • Portland General Electric
  • Pratt Whitney Rocketdyne
  • Progress Energy
  • Public Service Co.New Mexico
  • Richmond Power Light
  • Rio Tinto
  • Salt River Project
  • Shell
  • Siemens
  • Southern Company
  • Stanwell Corporation
  • Tri-State GT
  • TVA
  • TXU
  • U.S. DOE
  • We Energies
  • Wisconsin Public Service

CoalFleet Continues to Expand Collaborative
Relationship with International Organizations
  • Coordination with VGB for Europe and European
    firm participation
  • Growing Australian and Asian Involvement
  • Eskom adds African Involvement
  • Potential for Support from Asia-Pacific

PC Plant Efficiency and CO2 Reduction
Pulverized Coal with CO2 Capture (Today)
Energy Penalty 29
CO2 to Cleanup and Compression
Cleaned Flue Gas to Atmosphere
  • Amine commercially available (multiple suppliers)
  • 3 U.S. plants in operation
  • MEA, lt15 MWe, gt90 ?CO2
  • Key requirements
  • 56 acres for 600 MW plant
  • Near-zero SO2 and NO2
  • Large reboiler steam (MEAgtKS-1gtAmmonia)
  • Many new process options being explored

CO2 Stripper
Absorber Tower
Flue Gas from Plant
CO2 Stripper Reboiler
Needs Space, Integration and Energy
PC Operating Units w/ CO2 Capture (Today)
  • Three U.S. small plants in operation today
  • Monoethanolamine (MEA) based
  • CO2 sold as a product or used
  • Freezing chickens
  • Soda pop, baking soda
  • 140 /ton CO2 for food grade
  • 300 metric tons recovered per day
  • 15 MWe power plant equivalent
  • Many pilots planned and in development
  • 5 MWth Chilled Ammonia Pilot
  • Many other processes under development

Only Demonstrated on a Small Scale to Date
CO2 Capture Retrofits Require a Lot of Space(and
very clean flue gas)
CO2 capture plant for 500-MW unit occupies 6
acres, i.e. 510 ft x 510 ft
Potential Improvements for Post Combustion CO2
  • Alternative equipment arrangements and designs -
    membrane absorbers (Kvaerner, TNO), membrane
    regenerator (Kvaerner)
  • Alternative solvents Hindered Amine (MHI KS-1),
    Piperazine addition (promoter) to K2CO3, Other
    amines (PTRC at U. Regina)
  • Ammonium Carbonate with CO2 and water forms
    Ammonium Bicarbonate (EPRI/Alstom). Can be
    regenerated at pressure. Potential energy savings
    in regeneration and compression
  • Adsorption technologies Amine enriched solids,
    K, Na and Ca carbonates, Lithium oxide
  • Cryogenic cooling of flue gas
  • Recycle flue gas to increase CO2 concentration
    (perhaps viable for NGCC need to consider
    effect of lower oxygen)

Chilled Ammonia Process Performance Prediction
(Early Data Only)
Source Nexant
5 MW Chilled Ammonia CO2 Capture Pilot
  • Jointly Funded by Alstom and EPRI
  • Site- WE Energies Pleasant Prairie Power Plant
  • 11 million for construction, operation for one
    year, data collection and evaluation
  • Alstom will design, construct and operate
  • EPRI will collect data and provide evaluation
  • 24 firms have agreed to fund EPRI testing with
    more being added
  • Operations beginning in the 3rd Quarter of 2007
  • AEP plans 30 MWth at Mountaineer, WV site to be
    followed by further scale-up at OK site 2011.
  • Projects planned in Europe with EoN and Statoil
    capturing CO2 from Natural gas combustion (NGCC,
    Reformers , boilers )

5 MW Chilled Ammonia CO2 Pilot Capture Pilot
Gas takeoff
Scrubber Module
CO2 pilot location
5 MW Chilled Ammonia CO2 Capture Pilot
AEP Ameren CPS Energy Dairyland DTE Energy Dynegy
E.ON U.S. Exelon First Energy
SRP Southern Co Tri-State TXU TVA We Energies
Great River Energy Hoosier KCPL MidAmerican NPPD O
glethorpe Pacificorp PNM Sierra Pacific
CO2 Capture by O2/CO2 Combustion
  • O2/CO2 Combustion
  • Small test facilities at Canmet, BW, Alstom
  • Potential reuse of existing boiler equipment
  • Pulverizers, air heaters, etc.
  • Potential retrofit kit
  • CO2 recycled for temp. control
  • SO2 removed from purge stream
  • If higher purity CO2 required
  • Requires large oxygen plant
  • Large auxiliary power requirement
  • Large net output reduction
  • Make-up power source for Retrofit of existing

Oxyfuel Combustion in a PC Boiler
Other potential CO2 recycle take-off points
Source Vattenfall (GHGT7 2004)
Current Oxyfuel Development Status
  • Engineering design studies for commercial scale
    plants -(Air Products,
    Air Liquide, Jupiter Oxygen, Alstom, BW, etc)
  • Operation of several pilot scale boilers
  • CANMET ( 1 MM/Btu/hr)
  • Babcock and Wilcox (5 MMBtu/hr). Larger 30 MWth
    unit in construction
  • Alstom CFB (2.6-7.4 MMBtu/hr)
  • A key issue is the removal of other gases (SO2,
    O2, NOx, HCl, Hg). Is FGD required, at least for
    high sulfur coals, on either recycle or CO2
    product streams? To date there has been no
    testing of downstream non-condensable gas
    recovery system
  • To date no boiler testing at supercritical steam
  • Vattenfall 30 MWth Oxyfuel demo near Schwarze
    Pumpe, Germany
  • SaskPower FEED study for 300 MW net with BW, Air
  • AEP planned study of PC Retrofit with BW

Comparison of Oxyfuel and Amine Scrubbing
Preliminary Results for CCPC/DTI Project 366
(Canadian Dollars)
Oxyfuel is Competitive with Amine Scrubbing for
IGCC with and without CO2 Removal
IGCC no CO2 capture
H2 CO2 (e.g., FutureGen)
CO2 Capture , Space, Shift, H2 Firing, CO2
Removal, Energy
Coal Based IGCC Plants in Operation
Nuon- Buggenum, Netherlands 250 MW IGCC
Wabash 260 MW IGCC Repowering
Tampa Electric - Polk 250 MW IGCC
Salient Characteristics of Major Gasification
Technologies (Slide 1 of 2)
Salient Characteristics of Major Gasification
Technologies (Slide 2 of 2)
IGCC Environmental Control
  • Sulfur is removed (99.5-99.99) from syngas using
    commercial gas processing technology.
  • NOx emissions are controlled by firing
    temperature modulation in the gas turbine.
    Possible addition of SCR if needed.
  • Particulates are removed from the syngas by
    filters and water wash prior to combustion so
    emissions are negligible.
  • Current IGCC designs available with SCR to
    achieve 3ppmv each of SOx, NOx.
  • Mercury gt90 removed from the syngas by
    absorption on activated carbon bed.
  • Water use is lower than conventional coal
  • Byproduct slag is vitreous and inert and often
  • CO2 under pressure takes less energy to remove
    than from PC flue gas at atmospheric pressure.
    (Gas volume is lt1 of flue gas from same MW size

IGCC Commercial Teams 2004-5
  • GE Energy (Gasification and Power block) and
  • ConocoPhillips (E-Gas Gasification) and Fluor
  • Shell (Gasification and Gas cleanup), Krupp-Uhde
    and Black Veatch
  • Additional Candidates
  • MHI
  • Siemens
  • KBR-Southern Co

Coal Gasification Plants w/CO2 Capture (Today)
  • IGCC and CO2 removal offered commercially
  • Have not operated in an integrated manner
  • Three U.S. non-power facilities and many plants
    in China recover CO2
  • Coffeyville
  • Eastman
  • Great Plains
  • Great Plains recovered CO2 used for EOR
  • 2.7 million tons CO2 per year
  • 340 MWe if it were an IGCC

No Coal IGCC Currently Recovers CO2
IGCC with CO2 Removal
IGCC Pre-Investment Options for later addition of
CO2 Capture
  • Standard Provisions
  • Space for additional equipment, BOP, and site
    access at later date
  • Net power capacity, efficiency and cost penalty
    upon conversion to capture
  • Moderate Provisions
  • Additional ASU, Gasification and gas clean-up is
    needed to fully load the GTs when Shift is
  • If this oversizing is included in the initial
    IGCC investment the capacity can be used in the
    pre-capture phase for supplemental firing or
  • This version of capture ready would then permit
    full GT output with Hydrogen (at ISO) when
    capture is added. Mitigates the cost and
    efficiency penalty.
  • However when shift is added considerable AGR
    modifications will be required
  • Extensive Provisions
  • Design with conversion-shift reactors, oversized
    components, AGR absorber sized for shifted syngas
    but no CO2 absorber and compressor
  • No need for major shutdown to complete the
    conversion to CO2 capture

Water-Gas Shift Typical Process Configuration
Pressure in bar
Temp in ºC
Shift Reactors
Source Haldor Topsoe
Gas Compositions and Flows before and after
Shift- Adding Shift increases Syngas flow to
AGR (Mol Clean Dry Basis Typical Bituminous
Solvent Absorption for IGCC Generic Process Flow
Diagram with CO2 Capture Added
Have to add second absorber and stripper column
to capture CO2
IGCC with CO2 Capture from Day 1
  • Current EPRI IGCC Knowledge Base Gasification
  • 66 North America Projects
  • 38 International Projects

Summary - CO2 Capture Technology Status and Issues
  • IGCC and CO2 removal are offered commercially but
    have not operated in a mature integrated manner
  • Big issues IGCC Cost (particularly with low rank
    coals), Integration, and CO2 Storage
  • Advanced PC and CO2 post combustion are each
    offered commercially but CO2 removal has only
    operated at small scale and not integrated
  • Big issues CO2 Capture Cost Scale-up,
    Integration and CO2 Storage
  • Oxy-Fuel technology is in the early stages of
    development has only operated at small pilot
    plant facilities
  • Big issues Oxygen production cost and power
    consumption, Integration, CO2 purification and

Gasification and Combustion Needed With CO2
Plant Construction Costs Escalating
Capital Cost Estimates in Press Announcements and
Submissions to PUCs 2006-7 All Costs Are Way
Recent Duke PUC Submissions April/May 2007
  • Cliffside, NC 800 MW SCPC 1.8 B 0.6B
    Financing. Or 2250/kW
    750/kW financing Total 3000/kW
  • Scaling to 630 MW the cost would be 2417/kW.
    labor/productivity in NC is 0.9 (with MidWest
    1.0) this would become 2520/kW in the Mid West.
  • Edwardsport, IN 630 MW IGCC (GE RQ) 1.985B
    including escalation at 4/year through October
    2011. Factor (1.04)4 1.17 .
    Total 3151
    /kW with escalation to 2011 or 2693 /kW in
  • Consistent with Dukes statement in Edwardsport,
    IN filing that IGCC is 10-15 more than SCPC.
  • It is not completely clear what the costs
    represent (e.g. what is included or excluded).
    TPC? TPC OC? However it is assumed that they
    are fairly consistent.

Capital Cost Estimates
  • When comparing capital cost estimates, it is
    important to know what is included and, more
    importantly, what is not included!
  • Unfortunately, we do not know what is included in
    each of the capital cost estimates submitted to
    the PUCs. However, we believe most are similar to
    the EPRI Total Capital Requirement (TCR).
  • EPRI Total Capital Requirement is 1619 higher
    than Total Plant Cost
  • Typical EPRI Owners Costs add about 57 to TPC
  • AFUDC adds another 1112 to TPC
  • The adder for other Owners Costs varies widely
  • Depends on owner and site-specific requirements
  • Can easily add another 1015 to TPC

DOE NETL Draft Report Cost Performance
Comparison of Fossil Energy Power Plants
  • IGCC, PC and NGCC designs evaluated a) without
    capture and b) with Capture. Illinois6 coal
    1.34/MBtu NG 7.46/MBtu HHV.
  • GE Radiant Quench, COP E-Gas Full Slurry Quench,
    Shell Gas Recycle Quench . All based on 2 x GE 7
    FB GTs. Designs with capture have additional coal
    gasification etc to fully load the GTs when
    firing Hydrogen. Lower net output with capture.
    NETL presented results for IGCC as an average of
    the three technologies
  • PC sub critical (2400/1050/1050) and
    Supercritical (3500/1100/1100). Designs with post
    combustion amine scrubbing capture are much
    larger so that net output is same as designs
    without capture
  • NGCC without capture and with post combustion
    amine scrubbing

(No Transcript)
But IGCC technologies were not all created equal
!! - Particularly for CCS
  • Moisture is needed in the syngas for shift and
    the least expensive way of accomplishing this is
    direct water quench not by use of expensive
    syngas coolers
  • The DOE study used IGCC configurations with
    syngas coolers and the previous slide used an
    average of the three technologies.
  • Higher pressure (e.g., 8001000 psig) decreases
    the cost of CO2 removal and compression through
    use of a physical absorption system (e.g.,
  • DOE ranking with CCS - GE , COP, Shell
  • GE offers a direct quench (not in DOE study)
  • Shell is rumored to offer water quench design
  • COP is likely to offer a modified operation for
    capture to inject more water

Syngas Composition Affects Shift Steam
Requirements (Need gt31 H2O/CO Ratio) and Overall
EPRI CoalFleet Studies New Coal Plants 2006
  • Design Options in the face of Regulatory
    without CO2 Capture
    - Add Capture
    to Design without Capture
    - Design with Capture initially
  • Illinois 6, Wyoming Sub- bituminous coal (PRB)
  • Supercritical PC with Amine Scrubbing
    (Fluor Econamine ). Steam
    temperatures 565 C (Ill6) and 593 C (PRB).
    Single reheat.
  • IGCC
    - GE
    Radiant Quench (RQ) and Total Quench (Q) (Ill6)
    - Shell Gas Recycle Quench (Ill 6 PRB)
    - ConocoPhillips (COP)
    E Gas (Ill 6 PRB)

Basis for EPRI CoalFleet Program 2006 PC IGCC
Estimates - Nth and FOAK (First of a Kind)
  • Total Plant Costs (TPC) include total field
    costs, engineering, and contingency.
    Historically, usually estimated for Nth-of-a-kind
  • FOAK costs have not typically been included in
    previously reported estimates. However, in view
    of the current SOA and rapidly escalating costs,
    an additional 10 contingency has been added to
    the IGCC and CO2 capture designs.
  • Uncertain what the estimates presented to PUCs
    represent. Total Capital Requirement (TCR), which
    includes Owners costs and AFUDC is also reported
    because it is believed to be closer to what is
    reported to PUCs in project submissions
  • For PC plants, EPRI has used a TCR/TPC multiplier
    of 1.16, and estimates are shown as range -5 to
  • For IGCC plants, EPRI has used a TCR/TPC
    multiplier of 1.19, and estimates are shown as
    range -5 to 20
  • Most previous studies reported cost of capture at
    the battery limit. In this report, we have added
    10/mt for transportation, monitoring, and
    storage. So reported costs include CCS.
  • We recognize that the use of these additional
    contingencies, multipliers, and ranges for IGCC
    and CO2 capture is debatable. It is anticipated
    that they should be reduced as the technologies

Pulverized Coal with CO2 Capture Today
Energy Penalty 29
CO2 to Cleanup and Compression
Cleaned Flue Gas to Atmosphere
  • Amine commercially available (multiple suppliers)
  • 3 U.S. plants in operation
  • MEA, lt15 MWe, gt90 ?CO2
  • Key requirements
  • 56 acres for 600 MW plant
  • Near-zero SO2 and NO2
  • Large reboiler steam (MEAgtKS-1gtAmmonia)
  • Many new process options being explored

CO2 Stripper
Absorber Tower
Flue Gas from Plant
CO2 Stripper Reboiler
CO2 Capture , Space, Ultra-Low SO2, and Lots
of Energy.
EPRI 2006 PC Estimates
  • Adding Capture with Fluor Econamine to SCPC
    reduces net power from 600 to 425 MW net output
    ( 650 MW Gross power)
  • The SCPC retrofit for 90 CO2 recovery includes
    addition of Fluors Econamine FG Plus (EFG)
    process (MEA based chemical solvent), wet FGD
    upgrades to reduce the flue gas SO2 to 7 ppm (to
    reduce formation of heat stable salts in the MEA
    solvent), addition of a new cooling tower and
    circulating water system for Econamine FG
    cooling and the addition of CO2 drying and
    compression to 2000 psig. Steam must be extracted
    from the IP/LP cross over for regeneration of the
    solvent and modifications made to the LP steam
    turbine to accommodate the markedly reduced steam
  • Designing a 650 MW gross power SCPC for Capture
    would be designed for LP extraction and LP
    turbine would be appropriately sized so net would
    be 440 MW compared to 425 MW when retrofitted.
  • The SCPC designed for Capture is a larger boiler
    (800 MW gross 750 MW net) to give 550 MW net
    with capture. (Size chosen to compare with IGCC

IGCC with CO2 Removal via SOUR CO-Shift
HP Steam
IGCC Designs with Shift and CO2 Capture
  • Water quench is the least cost way of adding
    moisture for the water-gas shift reaction
  • Higher pressure (e.g., 8001000 psig) decreases
    the cost of CO2 removal and compression through
    use of a physical absorption system (e.g.,
  • GE can offer high pressure and either Quench (Q)
    or Radiant Quench (RQ) designs, which provide
    more moisture for the shift reaction
  • COP E-Gas, Shell, Siemens, and KBR are lower
    pressure (lt600 psig) and have lower moisture in
    the syngas
  • The loss of net power output with capture is
    greater for Shell (120 MW) than E-Gas (97 MW) and
    is least for the GE cases (78 MW).
  • When capture is added to an IGCC plant not
    designed initially for capture there is a further
    loss in net output (20-40 MW dependent on the
    technology) since the ASU and Gasification
    section are not sized to provide full fuel
    loading to the gas turbine.

EPRI PC and IGCC Net Power Output With and
Without CO2 Capture (Illinois 6 Coal)
EPRI PC and IGCC Capital Cost EstimatesWith and
Without CO2 Capture (Illinois 6 Coal)(All IGCC
and CCS cases have 10 Contingency for FOAK)
EPRI PC and IGCC Cost of ElectricityWith and
Without CO2 Capture (Illinois 6 Coal)(All IGCC
and CCS cases have 10 TPC Contingency for FOAK)
EPRI PC and IGCC Net Power OutputWith and
Without CO2 Capture (PRB Coal)
EPRI PC and IGCC Capital Cost EstimatesWith and
Without CO2 Capture (PRB Coal) (All IGCC and CCS
cases have 10 Contingency for FOAK)
EPRI PC and IGCC Cost of ElectricityWith and
Without CO2 Capture (PRB Coal) (All IGCC and CCS
cases have 10 Contingency for FOAK)
Cost Performance Penalties for CO2
Capture(based on retrofit of existing PC or IGCC
IGCC/Gasification Improvements Needed for More
Cost-Effective CO2 Capture
  • Need gas turbines that enable air extraction
    across the ambient temperature range and with
    hydrogen firing
  • GE Larger HP Quench new feed/design for
    low-rank coals
  • COP HP tall Cylinder higher throughput for
    low-rank coals
  • Shell Larger Quench (with water) design CO2
    transport of feed for capture and synthesis
    lower cost drying or new feeder for low-rank
  • Siemens Larger gasifier
  • Need larger (50 Hz New GTs), higher pressure,
    lower cost quench gasifiers for CO2 capture
    otherwise IGCC may lose its perceived advantage
    over PC for CCS

Coal Characteristics Drive Technology Selection
Nth Plant Economics
Economic Evaluations of SOA Coal Technologies
with CO2 Capture and Sequestration (CCS)-
Current Summary
  • At the current State-of-the Art (SOA) there is
    no Single Bullet technology for CCS. Technology
    selection depends on the location, coal and
  • IGCC/Shift least cost for bituminous coals
  • IGCC/Shift and PC plants with Amine scrubbing
    similar COE for high moisture Sub-bituminous
  • PC with Amine scrubbing least cost for Lignites
  • Although there is considerable added capital for
    Capture the major increase in COE is due to the
    high energy (power) losses and consequent
    reduction in net power for both PC and IGCC
  • Other notes
  • - CFBC can handle high ash coals and other low
    value fuels
  • - Oxyfuel (O2/CO2 Combustion), Chemical Looping
    are technologies at an earlier developmental

Basis used for LCOE with Retrofit
  • In the COE calculations for capture retrofit the
    entire TPC covering both the base plant and the
    retrofit cost is treated as though the 30 years
    applied to all the capital. This ignores any
    effect of Carbon Taxes and cost escalation over
  • Another approach would be to treat the base plant
    and its operation for some initial years with the
    capture retrofitted after the initial period.
    Appropriate timing for retrofit will depend on
    Carbon taxes , their , timing and trajectories.
  • This latter approach is similar to that be used
    for the EPRI CoalFleet Value of a Retrofit
    Capture Option study
  • The longer the initial plant can run without
    capture the lower will become the 30 year LCOE.

IGCC CO2 Capture Design Options
  • For slurry fed gasifiers the CO2 in the syngas
    can represent 20-25 of the coals carbon that
    could be removed without using the Shift
    reaction. This relatively small amount of capture
    is unlikely to generate much support from Federal
    or State Authorities.
  • For all gasification technologies can use sour
    High Temperature Shift followed by two column
    AGR. Maybe still use standard syngas GT
    combustors ? This could result in 60 -80 CO2
    capture which would satisfy Californias criteria
    that the CO2/MWH be no more than from NGCC. Lower
    COE than maximum capture option.
  • If gt 90 removal is required then both high and
    low temperature shift beds can be used. Needs
    Hydrogen combustors for GT. Higher COE.

Effect of Capital Cost Increases on
  • COE
  • CO2 Cost
  • Continued Operation of Existing PC plants
  • Strategic Selection of Future Generation
  • Conclusions

Effect of Carbon Tax on Cost of Electricity for
Various Technologies Bituminous Coal(All
evaluated at 80 CF, EPRI Estimates 2006 )
Effect of Increased Capital costs on Technology
and Fuel Selection with Carbon Taxes
  • Issue with the existing power plants. U.S. 320 GW
    of coal, 100 GW FGD but 50 GW planned. China
    soon 300 GW.
  • The paid off capital on most US coal plants is a
    great economic advantage. The large increase in
    capital costs over the last year means that IGCC
    or PC with capture would need a carbon tax
    gt250/mt C (or 62/st CO2) for their COE to be
    competitive with existing coal plants (with FGD
    SCR Hg removal) with venting CO2 and just
    paying the tax.
  • Up to 180/mt C tax USC with venting is lower COE
    than IGCC with CCS
  • With NG _at_ 8/MBtu new NGCC (at 80 CF) with CO2
    venting has COE similar to IGCC with CCS when the
    C tax is 250 /mt.
  • However with NG _at_ 8/MBtu and new NGCC at 40 CF
    venting is lower COE than new IGCC with capture
    until C tax is gt50/mt.

Future Coal Generation and CCS Issues and
  • Does CO2 Sequestration work? Where ? For how
    long? Multiple Integrated Demos urgently needed
  • Demand for New Coal Generation. However CCS costs
    add40-50 to COE for IGCC and 70-90 for PC
    with bituminous coals. Is this going to be
    acceptable? Can it be significantly reduced?
  • The paid off capital on most US coal plants is a
    great economic advantage. Even with adding FGD,
    SCR and Hg removal and a large C tax their COE
    would be much less than new coal. They will
    probably be kept going as long as possible (AEO
    2006) Question/Issue - How can CO2
    emissions be reduced from existing power plants?
  • Significant (gt50) CO2 reductions at new and
    existing coal plants can only be achieved with
    Question/Issue - Could Carbon tax proceeds be
    used to support the costs of CCS?

DOE CO2 Capture Market analysis(Source J.
Figueroa DOE NETL presentation to APPA June 28,
  • US 2005 CO2 emissions 6 Billion stpy, 39 from
    Electricity, 36 from coal (323 GW installed
  • AEO 2006 BAU forecast for 2030 - todays existing
    coal plants will be 66 of US Power CO2 emissions
    and 75 of all US coal CO2 emissions
  • Which of todays units are most likely to adopt
    CO2 capture under a regulatory environment?
  • Existing boilers gt 300 MW and gt 35 years old
    represent 184 GW. If 90 CO2 capture was applied
    to these units this would provide a 50 reduction
    in coal power CO2 emissions
  • Q. What is the cost of adding capture to these
    existing plants and the cost and source of
    replacement power?

U.S. CO2 Retrofit Capture CostAn
Order-of-Magnitude Estimate
  • EPRI estimate 343M TCR for MEA retrofit to 600
    MW PC. Use retrofit factor 1.35. Assume 2011
    ISD (5 yrs _at_ 5) 1.276.
  • 184 GW assume all 600 MW units 307 units
  • Retrofit Cost 307 x 343 x 106 x 1.35 x 1.276
    181 billion
  • Power reduction from 600 MW unit 175 MW
  • Replacement power needed 175 x 306 units 53.7
  • EPRI estimate for new SCPC with capture TCR
    1.9 billion for 550 MW net or 3,455/kW
  • Cost of replacement power (Assume 2011 ISD)
    53.7 x 3455 x 106 x 1.276 237 billion
  • Need to add Costs for CO2 Transportation and

  • All generation options (Coal, Natural Gas,
    Nuclear, Renewables) will probably still be
    needed in a Carbon Constrained World
  • Emissions for all new coal plants are down
    approaching near zero without CO2 capture
  • Costs for new coal plants have increased markedly
  • CO2 Capture is costly for both IGCC and PC plants
    and probably feasible integrated CCS costs
  • EPRI believes PC and IGCC will compete in the
    future even with capture for some coals and
  • Multiple Storage (preferably Integrated CCS)
    demonstrations needed ASAP at large scale.
    Liability for the CO2 needs resolution.

Post Combustion CO2 Capture
  • Adding Capture to IGCC not designed for Capture
  • Preliminary Study on Partial Capture from GE
    Quench IGCC
  • Caution on Reported CO2 Avoided Capture costs
  • COE for NGCC plants at 40 CF and at 6 8 /MBtu
    with and without capture. Including effect of
    Carbon tax on decision to either a) Vent and pay
    tax or b) add capture.

IGCC Design Issues for adding Capture to a Plant
designed without Capture
  • Addition of Sour Shift increases gas flow to the
    AGR particularly for the dry coal fed gasifiers
    with high CO content (next slide). Unlikely that
    the AGR would be able to take the extra flow
    unless there was pre-investment oversizing. May
    need to add a parallel absorber or replace the
    entire AGR plant (with a new two column
    absorption system) if capture is to be added to
    an existing IGCC designed without capture.
  • Alternatively the original AGR (focused on H2S
    Removal) could be retained and a Sweet shift
    added after the AGR with a simpler bulk CO2
    removal AGR (ADIP, MDEA, Selexol) added after
    shift. This would minimize intrusion into
    existing plant. This trade off of Sour versus
    Sweet Shift needs to be examined and may differ
    among the Gasification Technologies. Sweet Shift
    may incur additional efficiency and output
    penalties. Quench gasifiers would probably favor
    Sour Shift.

2006 IGCC Estimates Adding Capture to IGCC not
designed for Capture
  • The IGCC designs are without spare gasifiers and
    are based on 2 x GE 7 FB GTs. For the designs
    without capture 30-40 of the air supply for the
    ASU is extracted from the gas turbine compressor.
    Since GE has stated that no air can be extracted
    when firing Hydrogen another air compressor needs
    to be added to fully supply the ASU when capture
    is added.
  • IGCC retrofit for 90 CO2 recovery includes
    replacement of COS/HCN hydrolysis reactor with 2
    stages of sour shift reaction, additions to
    syngas cooling train for the shift reactors,
    additions to or replacements of the AGR to
    recover CO2 as a separate by-product, upgrade of
    the demineralizer water treatment and storage
    system, IP steam for water-gas shift reaction (in
    some cases), HRSG LP superheater modifications
    and addition of CO2 drying and compression to
    2000 psig (138 barg).
  • Since no extra ASU or gasification capacity was
    included in the original designs there is a lower
    net power output with capture because some
    chemical energy is lost in the shift reaction so
    that the gas turbine cannot be fully loaded when
    the capture capability is added.

2006 Adding Capture to IGCC not designed for
Capture Effect on AGR Section
  • The GE Radiant Quench IGCC without capture can
    use either MDEA (no SCR) or Selexol (if SCR is
    needed). When adding capture to a plant designed
    originally with MDEA the MDEA must be replaced
    with a new 2 absorber Selexol for separate H2S
    and CO2 removal.
  • If the original design used Selexol for H2S
    removal then either a new parallel absorber
    column will need to be added to accommodate the
    additional flow of syngas from the shift reactors
    or a completely new absorber designed for the
    full flow must be added. In all cases a new
    Selexol CO2 absorber/stripper system must be
  • COP case without capture has MDEA so the MDEA
    must be replaced with a new 2 section Selexol for
    separate H2S and CO2 removal.
  • The Shell case without capture used the Sulfinol
    process so the Sulfinol must be replaced with a
    new 2 section Selexol for separate H2S and CO2

Interim Conclusions on IGCC with Provisions for
later Addition of CCS
  • IGCC with Standard Provisions of Space not very
    CCS ready
  • IGCC with some Moderate Provisions are much more
    CCS ready Incremental Capital may be justified
  • AGRU/SRU for CCS Selexol more ready than MDEA-
    particularly with Moderate Provisions
  • Sour Shift more CCS ready than Sweet
  • Quench with Sour shift is CCS ready. SGC designs
    with either Sour or Sweet Shift less ready for
  • Major Issues H2S content of CO2
  • - Thermodynamic penalty for Syngas reheat and HP
    steam injection (with Sweet CO shift and non
    Quench gasifiers)

Preliminary Study of Impact of CO2 Capture on
IGCC COE CO2 Avoided Cost (without
Transportation Storage) (GE Quench, June 2006
Basis, Bituminous coal)
CO2 Capture Costs- Cautions
  • The basic assumptions for calculation of COE vary
    between studies.
  • Assumptions that lead to lower COE and
    particularly a lower capital cost component of
    the COE lead to lower avoided costs for CO2
    Capture (See next Slide)
  • - a lower capital charge rate (e.g. US DOE/EPRI
    15 Europe 11-12)
  • - a higher assumed Capacity Factor (e.g.
    DOE/EPRI 80 IEA 85-90)
  • - a larger capacity plant with economies of
    scale (e.g. IEA 800 MW versus DOE/EPRI 500 MW)
  • - a lower cost of fuel (e.g. IEA Natural gas at

Avoided or Mitigation Cost of CO2 Capture
Storage (CCS) Is this the best Metric?
  • Avoided cost or Mitigation Cost is defined as
  • (COE with CCS COE Reference) divided by
  • (mt CO2/MWhReference mt CO2/MWh with CCS)
  • What is the Reference case?
    Conventionally the same
    technology without CCS has been used as the
    reference. Is this the most relevant?
  • Should the reference case should be the
    technology that would have been used if no CCS
    was required?
  • Perhaps the more appropriate measure is COE.
    After all it is on this basis that technology
    selection is really made (while conforming to all
    applicable regulations)

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