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Update on Clean Coal Technologies and CO 2 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 CO 2 Capture and Storage (CCS) - Presentation Outline.

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Update on clean coal technologies and co 2 capture storage

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 co 2 capture and storage ccs presentation outline
Clean Coal Technologies (CCT) and CO2 Capture and Storage (CCS) - Presentation Outline

  • Overview – Options for Response to Global Climate concerns

  • Clean Coal Technology (CCT) Options

  • EPRI CoalFleet Program

  • PC Post Combustion Removal – Status, Chilled Ammonia

  • 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 co 2 emissions
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 States)

    • Powering the Plains (ND,SD,IA,MN,WI, Manitoba)

  • California: Governor’s 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 (>5years) commitments shall have CO2 emissions no greater than NGCC (established as <1100 lbs/MWh).

    • Oregon & Washington have enacted similar legislation

  • Liability of CO2 injection into geological formations ?

Power company carbon management options


Energy Storage


Power Company Carbon Management Options

Options for co 2 response the stabilization wedge slices
Options for CO2 Response(The Stabilization Wedge & Slices)

  • Conservation (Yes - but Rest of the World?)

  • Renewables (Yes - but not enough)

  • Nuclear (Ultimately Yes – but implies wide Proliferation)

  • 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 > 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

Co 2 capture in coal power systems
CO2 Capture in Coal Power Systems

New technology deployment curve for coal





Mature Technology

Advanced USCPC Plants



CO2 Capture

USCPC Plants



IGCC Plants

Anticipated Cost of Full-Scale Application




SCPC Plants

CO2 Storage


New Technology Deployment Curve for Coal

Not All Technologies at the Same Level of Maturity.

Epri programs 2007ff
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 (IGCC,PC,CFBC)

    - 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 GHG

    - Capture focus Existing Plants

    - Chilled Ammonia (ABS) 5 MW Pilot Plant

Epri s c oalfleet for tomorrow program
EPRI’s CoalFleet forTomorrow Program

  • Build an industry-led program toaccelerate the deployment ofadvanced coal-based power plants;use “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 RD&D 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 combustion)

    • Lower costs, especially with CO2 capture

    • Higher reliability

    • Near-zero SOX, NOX, PM, and Hg emissions

    • Shorter project schedule

Further information availableat www.epri.com/coalfleet

Update on clean coal technologies and co2 capture storage

CoalFleet Participants Span 5 Continents>60% of U.S. Coal-Based Generation, Large European Generators,Major OEMs (50 & 60 Hz) and EPCs, U.S. DOE

  • 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 cont d
CoalFleet Participants Span 5 Continents (cont’d)

  • 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 G&T

  • TVA

  • TXU

  • U.S. DOE

  • We Energies

  • Wisconsin Public Service

Coalfleet continues to expand collaborative relationship with international organizations
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 Partnership

Pc plant efficiency and co 2 reduction

2 Percentage Point Efficiency Gain = 5% CO with International Organizations2 Reduction

Commercial Supercritical Plant Range

Subcritical Plant Range

Advanced Ultra-Supercritical Plant Range

PC Plant Efficiency and CO2 Reduction

Pulverized coal with co 2 capture today

CO with International Organizations2 to Use or Sequestration

Fresh Water



e.g., MEA




Flue Gas

to Stack





Fly Ash




Pulverized Coal with CO2 Capture (Today)

  • Amine commercially available (multiple suppliers)

  • 3 U.S. plants in operation:

    • MEA, <15 MWe, >90% ΔCO2

  • Key requirements:

    • ~5–6 acres for 600 MW plant

    • Near-zero SO2 and NO2

    • Large reboiler steam (MEA>KS-1>Ammonia)

  • Many new process options being explored

Energy Penalty ~29%

CO2 to Cleanup

and Compression

Cleaned Flue Gas to Atmosphere

CO2 Stripper

Absorber Tower

Flue Gas from Plant

CO2 Stripper Reboiler

Needs Space, Integration and Energy

Pc operating units w co 2 capture today

E with International Organizations




AES Cumberland ~ 10 MW

(Report 1012796)

Assessment of Post-Combustion Carbon Capture Technology


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

Co 2 capture retrofits require a lot of space and very clean flue gas
CO with International Organizations2 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 co 2 capture
Potential Improvements for Post Combustion CO with International Organizations2 Capture

  • 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)

5 mw chilled ammonia co 2 capture pilot
5 MW Chilled Ammonia CO Only)2 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 co 2 pilot capture pilot
5 MW Chilled Ammonia CO Only)2 Pilot Capture Pilot

Gas takeoff

Scrubber Module

CO2 pilot location

5 mw chilled ammonia co 2 capture pilot participants
5 MW Chilled Ammonia CO Only)2 Capture Pilot Participants



CPS Energy


DTE Energy Dynegy E.ON U.S.


First Energy

Great River Energy








Sierra Pacific


Southern Co




We Energies

Co 2 capture by o 2 co 2 combustion
CO Only)2 Capture by O2/CO2 Combustion

  • O2/CO2 Combustion

  • Small test facilities at Canmet, B&W, 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 plant?

Oxyfuel combustion in a pc boiler
Oxyfuel Combustion in a PC Boiler Only)

Other potential CO2recycle take-off points

Source: Vattenfall (GHGT7 2004)

Current oxyfuel development status
Current Oxyfuel Development Status Only)

  • Engineering design studies for commercial scale plants -(Air Products, Air Liquide, Jupiter Oxygen, Alstom, B&W, 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 conditions

  • Vattenfall 30 MWth Oxyfuel demo near Schwarze Pumpe, Germany

  • SaskPower FEED study for 300 MW net with B&W, Air Liquide

  • AEP planned study of PC Retrofit with B&W

Update on clean coal technologies and co2 capture storage

R0 is base case (no capture), A1 is oxyfuel, B1 is amine scrubbing.

Triangles indicate COE if CO2 was sold for $42/tonne.




Comparison of Oxyfuel and Amine ScrubbingPreliminary Results for CCPC/DTI Project 366 (Canadian Dollars)

Oxyfuel is Competitive with Amine Scrubbing for PRB

Igcc with and without co 2 removal

Sulfur scrubbing.


Gas Clean Up

CC Power Block










CC Power Block

Gas Clean Up









IGCC with and without CO2 Removal

IGCC no CO2 capture

H2 & CO2

(e.g., FutureGen)

CO2 Capture = $, Space, Shift, H2 Firing, CO2 Removal, Energy

Igcc environmental control
IGCC Environmental Control scrubbing.

  • 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 >90% removed from the syngas by absorption on activated carbon bed.

  • Water use is lower than conventional coal (70-80%).

  • Byproduct slag is vitreous and inert and often salable.

  • CO2 under pressure takes less energy to remove than from PC flue gas at atmospheric pressure. (Gas volume is <1% of flue gas from same MW size PC).

Igcc commercial teams 2004 5
IGCC Commercial Teams 2004-5 scrubbing.

  • GE Energy (Gasification and Power block) and Bechtel

  • ConocoPhillips (E-Gas Gasification) and Fluor

  • Shell (Gasification and Gas cleanup), Krupp-Uhde and Black & Veatch

    Additional Candidates:



    KBR-Southern Co

Coal gasification plants w co 2 capture today

The Great Plains Synfuels Plant scrubbing.


Weyburn Pipeline


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 co 2 removal

HP Steam scrubbing.


CO2to use or sequestration

GasificationC + H2O = CO + H2

Sour Shift

CO+ H2O =

CO2 + H2


H2S & CO2



Gas Cooling




Air Separation Unit









IGCC with CO2 Capture(e.g., FutureGen, BP Carson)

Steam Turbine

Needs Space, Energy and Integration

IGCC with CO2 Removal

Igcc pre investment options for later addition of co 2 capture
IGCC Pre-Investment Options for later addition of CO scrubbing. 2 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 GT’s when Shift is added.

    • If this oversizing is included in the initial IGCC investment the capacity can be used in the pre-capture phase for supplemental firing or co-production.

    • 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
Water-Gas Shift: Typical Process Configuration scrubbing.

Pressure in bar

Temp in ºC

Shift Reactors

Source: Haldor Topsoe

Update on clean coal technologies and co2 capture storage

Gas Compositions and Flows before and after Shift scrubbing. - Adding Shift increases Syngas flow to AGR(Mol % Clean Dry Basis – Typical Bituminous Coal)

Solvent absorption for igcc generic process flow diagram with co 2 capture added

Clean H scrubbing. 2-rich syngas


CO2 Removal

H2S Removal

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 co 2 capture from day 1

15 Gasification Projects Aimed at C&S – Day 1 scrubbing.

  • BP Carson

  • Xcel

  • Pacificorp Wyoming

  • FutureGen Demo

  • Hunton 10-15%

  • Indiana Gasification

  • TransCanada Polygen

  • Wallula RR, Washington

  • RWE

  • Stanwell ZeroGen Demo

  • Centrica / Progressive Energy

  • EoN UK

  • Powerfuel Hatfield UK

  • GreenGen Demo China

  • BP/Rio Tinto Australia

IGCC with CO2 Capture from Day 1

  • Current EPRI IGCC Knowledge Base Gasification Projects

    • 66 North America Projects

    • 38 International Projects

Summary co 2 capture technology status and issues
Summary - CO scrubbing. 2 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 issuesCO2 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 issuesOxygen production cost and power consumption, Integration, CO2 purification and Storage

Gasification and Combustion Needed With CO2 Options

Capital cost estimates in press announcements and submissions to pucs 2006 7 all costs are way up
Capital Cost Estimates in Press Announcements and Submissions to PUCs 2006-7 — All Costs Are Way Up!

Recent duke puc submissions april may 2007
Recent Duke PUC Submissions April/May 2007 Submissions to PUCs 2006-7

  • 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$/kW. If labor/productivity in NC is 0.9 (with MidWest 1.0) this would become ~2520$/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 2007.

  • Consistent with Duke’s 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
Capital Cost Estimates Submissions to PUCs 2006-7

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 16–19% higher than Total Plant Cost

    • Typical EPRI Owner’s Costs add about 5–7% to TPC

    • AFUDC adds another 11–12% to TPC

  • The adder for “other” Owner’s Costs varies widely

    • Depends on owner and site-specific requirements

    • Can easily add another 10–15% to TPC

Doe netl draft report cost performance comparison of fossil energy power plants
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. Illinois#6 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

But igcc technologies were not all created equal particularly for ccs
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., 800–1000 psig) decreases the cost of CO2 removal and compression through use of a physical absorption system (e.g., Selexol)

  • DOE ranking with CCS - GE , COP, Shell

  • GE offers a direct quench (not in DOE study)

  • Shell is rumored to offer water quench design soon

  • COP is likely to offer a modified operation for capture to inject more water

Syngas composition affects shift steam requirements need 3 1 h 2 o co ratio and overall performance
Syngas Composition Affects Shift Steam Requirements (Need >3:1 H2O/CO Ratio) and Overall Performance

Epri coalfleet studies new coal plants 2006
EPRI CoalFleet Studies New Coal Plants 2006+ >3:1 H

  • Design Options in the face of Regulatory Uncertainty: – Design 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 (Ill#6) and 593 C (PRB). Single reheat.

  • IGCC - GE Radiant Quench (RQ) and Total Quench (Q) (Ill#6) - Shell Gas Recycle Quench (Ill #6 & PRB) - ConocoPhillips (COP) E Gas (Ill #6 & PRB)

Basis for epri coalfleet program 2006 pc igcc estimates n th and foak first of a kind
Basis for EPRI CoalFleet Program 2006 PC & IGCC Estimates - >3:1 HNth 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 plants.

  • 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 +10%

  • 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 mature.

Pulverized coal with co 2 capture today1

CO >3:1 H2 to Use or Sequestration

Fresh Water



e.g., MEA




Flue Gas

to Stack





Fly Ash




Pulverized Coal with CO2 Capture “Today”

  • Amine commercially available (multiple suppliers)

  • 3 U.S. plants in operation:

    • MEA, <15 MWe, >90% ΔCO2

  • Key requirements:

    • ~5–6 acres for 600 MW plant

    • Near-zero SO2 and NO2

    • Large reboiler steam (MEA>KS-1>Ammonia)

  • Many new process options being explored

Energy Penalty ~29%

CO2 to Cleanup

and Compression

Cleaned Flue Gas to Atmosphere

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
EPRI 2006 PC Estimates >3:1 H

  • 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 Fluor’s 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 flow.

  • 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 cases)

Igcc with co 2 removal via sour co shift

Sulfur >3:1 H

CO2to use or sequestration

GasificationC + H2O = CO + H2

Sour Shift

CO+ H2O =

CO2 + H2


H2S & CO2



Gas Cooling?




Air Separation Unit









Steam Turbine

IGCC with CO2 Removal via SOUR CO-Shift

HP Steam

Igcc designs with shift and co 2 capture
IGCC Designs with Shift and CO >3:1 H2 Capture

  • Water quench is the least cost way of adding moisture for the water-gas shift reaction

  • Higher pressure (e.g., 800–1000 psig) decreases the cost of CO2 removal and compression through use of a physical absorption system (e.g., Selexol)

  • 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 (<600 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 co 2 capture illinois 6 coal
EPRI PC and IGCC Net Power Output With >3:1 Hand Without CO2 Capture (Illinois #6 Coal)

Update on clean coal technologies and co2 capture storage

EPRI PC and IGCC Capital Cost Estimates >3:1 HWith and Without CO2 Capture (Illinois #6 Coal)(All IGCC and CCS cases have +10% Contingency for FOAK)

Update on clean coal technologies and co2 capture storage

EPRI PC and IGCC Cost of Electricity >3:1 HWith and Without CO2 Capture (Illinois #6 Coal)(All IGCC and CCS cases have +10% TPC Contingency for FOAK)

Epri pc and igcc net power output with and without co 2 capture prb coal
EPRI PC and IGCC Net Power Output >3:1 HWith and Without CO2 Capture (PRB Coal)

Update on clean coal technologies and co2 capture storage

EPRI PC and IGCC Capital Cost Estimates >3:1 HWith and Without CO2 Capture (PRB Coal) (All IGCC and CCS cases have + 10% Contingency for FOAK)

Update on clean coal technologies and co2 capture storage
EPRI PC and IGCC Cost of Electricity >3:1 HWith and Without CO2 Capture (PRB Coal) (All IGCC and CCS cases have + 10% Contingency for FOAK)

Cost performance penalties for co 2 capture based on retrofit of existing pc or igcc plant
Cost & Performance Penalties for CO >3:1 H2 Capture(based on retrofit of existing PC or IGCC plant)

Igcc gasification improvements needed for more cost effective co 2 capture
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 coals

  • 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
Coal Characteristics Drive Technology Selection Cost-Effective CO

Nth Plant Economics

Update on clean coal technologies and co2 capture storage
Economic Evaluations of SOA Coal Technologies Cost-Effective COwith 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 application

  • IGCC/Shift least cost for bituminous coals

  • IGCC/Shift and PC plants with Amine scrubbing similar COE for high moisture Sub-bituminous Coals

  • 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 stage

Basis used for lcoe with retrofit
Basis used for LCOE with Retrofit Cost-Effective CO

  • 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 time.

  • 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 co 2 capture design options
IGCC CO Cost-Effective CO2 Capture Design Options

  • For slurry fed gasifiers the CO2 in the syngas can represent 20-25% of the coal’s 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 California’s criteria that the CO2/MWH be no more than from NGCC. Lower COE than maximum capture option.

  • If > 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
Effect of Capital Cost Increases on: Cost-Effective CO

  • COE

  • CO2 Cost

  • Continued Operation of Existing PC plants

  • Strategic Selection of Future Generation

  • Conclusions

Update on clean coal technologies and co2 capture storage
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
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 >250$/mt C (or ~62$/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 @ 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 @ 8$/MBtu and new NGCC at 40% CF venting is lower COE than new IGCC with capture until C tax is >50$/mt.

Future coal generation and ccs issues and observations
Future Coal Generation and CCS Selection with Carbon Taxes – Issues and Observations

  • Does CO2 Sequestration work? Where ? For how long? Multiple Integrated Demos urgently needed ASAP.

  • Demand for New Coal Generation. However CCS costs add~40-50% 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 (>50%) CO2 reductions at new and existing coal plants can only be achieved with CCS. Question/Issue - Could Carbon tax proceeds be used to support the costs of CCS?

Doe co 2 capture market analysis source j figueroa doe netl presentation to appa june 28 2006
DOE CO Selection with Carbon Taxes 2 Capture Market analysis(Source J. Figueroa DOE NETL presentation to APPA June 28, 2006)

  • US 2005 CO2 emissions 6 Billion stpy, 39% from Electricity, 36% from coal (323 GW installed capacity)

  • AEO 2006 BAU forecast for 2030 - today’s existing coal plants will be 66% of US Power CO2 emissions and 75% of all US coal CO2 emissions

  • Which of today’s units are most likely to adopt CO2 capture under a regulatory environment?

  • Existing boilers > 300 MW and > 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 co 2 retrofit capture cost an order of magnitude estimate
U.S. CO Selection with Carbon Taxes 2 Retrofit Capture Cost—An 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 @ 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 GW

  • 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 Storage

Summary Selection with Carbon Taxes

  • 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 uncertain

  • EPRI believes PC and IGCC will compete in the future even with capture for some coals and conditions

  • Multiple Storage (preferably Integrated CCS) demonstrations needed ASAP at large scale. Liability for the CO2 needs resolution.


IGCC Selection with Carbon Taxes





Post Combustion

CO2 Capture

Appendices Selection with Carbon Taxes

  • 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
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
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
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 added.

  • 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 removal.

Interim conclusions on igcc with provisions for later addition of ccs
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 CCS

  • Major Issues – H2S content of CO2

    - Thermodynamic penalty for Syngas reheat and HP steam injection (with Sweet CO shift and non Quench gasifiers)

Update on clean coal technologies and co2 capture storage

Preliminary Study of Impact of CO Addition of CCS2 Capture on IGCC COE & CO2 Avoided Cost (without Transportation & Storage)(GE Quench, June 2006 $ Basis, Bituminous coal)

Co 2 capture costs cautions
CO Addition of CCS2 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 2$/GJ)

Avoided or mitigation cost of co 2 capture storage ccs is this the best metric
Avoided or Mitigation Cost of CO Addition of CCS2 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)