reducing co2 emissions from coal-fired power plants · •supporting test program for mhi’s...

CoalFleet for Tomorrow®

CoalFleet for Tomorrow® is a registered service mark

of Electric Power Research Institute, Inc.

Reducing CO2 Emissions from Coal-Fired Power Plants

John Wheeldon ([email protected])

EPRI Advanced Coal Generation

CCTR Advisory Panel Meeting,Vincennes University, September 10th, 2009

2© 2007 Electric Power Research Institute, Inc. All rights reserved.

When CO2 Capture Included, Higher PC Efficiency Lowers Levelized Cost-of-Electricity

Capture only. No allowance for transportation and storage.

1.10

1.20

1.30

1.40

1.50

30 35 40 45 50

Efficiency of PC plant without CO2 capture, % (HHV)

Rela

tive C

OE

, -

Pittsburgh #8 PRB

Based on KS-1 solvent, but oxy-

combustion considered similar

Potential range of COE increase with improvements in CCS technology either post-combustion capture or oxy-combustion


Performance Summary: 1300°F USC PC

Subcritical Supercritical 1100 USC 1300 USC

Main stream, °F 1005 1080 1120 1256

Main steam, psia 2600 3800 4000 5100

Efficiency, % HHV 36.5 38.5 39.2 42.7

Coal flow lb/hr 840,600 797,000 782,700 718,600

Flue gas, ACFM 2,107,000 2,016,000 1,982,000 1,823,000

Make-up water, gpm 4,260 3,750 3,650 3,310

NOX & SO2, lb/MWh 0.280 0.266 0.261 0.240

CO2, lb/MWh from plant 1980 1880 1840 1690

CO2, lb/MWh from mining

and transportation (*)146 139 136 125

(*) Values based on life-cycle assessment model prepared by Carnegie Mellon University

CO2 emissions from 1300°F USC unit is 14.7% lower than emissions rate

(per MWh) from subcritical unit


Further Efficiency Improvements Identified

• Increase main steam temperature to 1400°F

– US DOE sponsoring research into boiler and steam turbines materials (mainly high-nickel alloys).

• Double reheat steam circuit.

• Back-end heat recovery

– Widely practiced in Europe and Japan.

• Pass primary air through tubular heat exchanger to reduce air leakage by 80 percent.

• Potential to reduce CO2 emissions to 1500 lb/MWh

– Over 40 percent lower than US fleet average.

• Cautionary note: all measures may not be cost effective.


Demonstration of Improvements : EPRI’s UltraGen Initiative

• Series of three commercial power projects and a test facility that progressively advance USC, NZE, and CCS technology

– UltraGen I—800 MW net, main steam 1120°F, 25% CO2 capture

– UltraGen II—600 MW net, main steam 1290°F, 60% CO2 capture

– ComTes-1400 to test materials and components for UltraGen III

– UltraGen III—600 MW net, main steam 1400°F, 90% CO2 capture

• The UltraGen projects are commercial units dispatched by their hosts (i.e., the host operates them for profitability) that incorporate technology demonstration elements

– Host’s incremental cost for new technology elements will be covered by tax credits and funds from industry-led consortium


CO2 Post-Combustion Capture (PCC) Plant

Flue Gas Out

(~1.5% CO2)

CO2 to Compressors

(+99.9% purity)

Steam

Flue Gas

(~14% CO2)

CW

CW

CW

ABSORBER

(~110°F)

FLUE GAS

COOLER

STRIPPER

(~250°F)

Rich Amine

Solution

Lean Amine

Solution

Condensate

SO2 POLISHING

WITH CAUSTIC

Cooling, power, and

solvent make-up


Power Plant Losses Associated with Post-Combustion Capture Using Advanced Amine

Main steam temperatures: (1) 1005°F, (2) 1050°F, (3) 1260°F

(4) Net output without CCS = 750 MW. Losses for 90 percent CO2 capture

Sub (1) SC (2) USC (3)

Efficiency, % HHV 36.5 38.2 42.5

lb CO2/MWh 1970 1880 1690

Losses, MW (4)

Auxiliary power 9.2 8.6 7.5

Compressors 49.5 47.0 41.0

Steam turbine 93.9 89 77.9

TOTAL 152.6 144.6 126.4

% reduction 20.3 19.3 16.9

Efficiency with CCS, % HHV 29.3 31.2 36.9

Percentage point loss 7.2 7.0 5.6


Solvent Used Strongly Influences PCC Plant Performance

• Need solvents with superior properties

– High CO2 loading to limit sensible heat duty

– Low heat of reaction

– Tolerant to contaminants

– Regenerate at elevated pressure

• Significant development activity in progress

– Amines: Aker, Alstom with Dow, Cansolv, HTC PurEnergy, MHI, TNO, and Toshiba

– Amino acid salts: BASF, TNO, and Siemens

– Ammonia: Alstom and Powerspan

– Anhydrase enzymes: CSIRO and CO2 Solutions

• Alternative approaches such as adsorption, algae, and membranes under investigation.


EPRI Role in Demonstrating Improved Post-Combustion CO2 Capture Technologies

• Supporting test program for Alstom’s chilled ammonia process at two locations

– 1.7-MW pilot plant at We Energies’ Pleasant Prairie power plant

– 20-MW ―product validation facility‖ at AEP’s Mountaineer plant that captures and stores over 120,000 tons/year of CO2.

• Supporting test program for MHI’s advanced amine process at a Southern Company’s Plant Barry, near Mobile, Alabama

– 25-MW facility that captures and stores over 150,000 tons/year of CO2 in support of Southeast Regional Carbon Sequestration Partnership Program (SECARB).

• Supporting DOE’s National Carbon Capture Center in Wilsonville, Alabama

– Supporting development of improved pre- and post-combustion capture technologies.


Power Plant Losses for Different Percentages of CO2 Capture

(1) Steam required for solvent regeneration

(2) Net output without CCS = 750 MW

90 60 30

Steam extraction, % (1) 25 17 8

Losses, MW (2)

Auxiliary power 9.2 6.1 3.1

Compressors 49.5 33.0 16.5

Steam turbine 93.9 62.6 31.3

TOTAL 152.6 101.7 50.9

% reduction 20.3 13.5 6.8

CO2 capture, M-tons/yr 4.66 3.11 1.55

Percent CO2 capture


Space and Storage Requirements for CCS

• Space required for

– Capture plant, CO2 compressors, and added cooling capacity

– Power plant interconnections and maintenance,

– Routing steam piping, flue gas ducting

– Construction activities

– Possible upgrades to SO2 and NOX controls

• Space a limiting factor setting achievable percent CO2 capture

– Riverside plant with FGD may have no space available

• Suitable geological strata to store CO2 or prospects for extended duration EOR


Retrofits Require a Lot of Space:

First Come, First Served

CO2 capture plant for 500-MW unit occupies 6 acres (i.e., 510 ft x 510 ft)


• Owner:

MidWest

Generation

• Location: Illinois

• Owner:

Great River Energy

• Location: North

Dakota

• Owner:

Nova Scotia

Power

• Location: Nova

Scotia

• Owner:

Intermountain

Power

• Location: Utah

• Owner:

FirstEnergy

• Location: Ohio

EPRI Retrofit Study

EPRI Retrofit Study Considers:

• 5 different sites

• 5 separate owners

• Different designs of plant and emission control technologies

• Focus on establishing several different data points


One Steam Extraction Option

Source: Imperial College London

Thrust

balance point

Desuperheater can

be replaced by

expansion turbine to

recoup some of the

energy

At high steam extraction rates thrust bearing design changes

required. Below 15 percent design changes not required (~60

percent CO2 capture)


PCC

System

Let-Down Turbine and Condensate Return: Heat Integration

G


PCC

System

PC Plant with PCC: Heat Integration

G

Heat from CO2 stripper condenser

and CO2 compressors


California’s “De Facto” Coal Moratorium

• In January 2007, California became first state to place ―de facto moratorium‖ on new coal plants

– Set the standard for CO2

emissions at 1100 lb-CO2/MWh (500 kg-CO2/MWh )

– Washington state has followed a similar approach

Pulverized Coal at 90%

CO2 Capture = 180 lb/MWh (80 kg/MWh)

Pulverized Coal Plant = 1760 lb/MWh

(800 kg/MWh)

CTCC = 800 lb/MWh

(360 kg/MWh)

California Standard = 1100 lb/MWh

(500 kg/MWh)

~80%

capture

required on

CTCC?


Concluding Remarks

• CO2 capture from flue gas has been carried out at small scale (~20 MW) for high-value applications in chemical and food industries.

• For power industry need larger plants that minimize increase in cost of electricity

– Current designs are estimated to result in a 60 percent increase.

• Part of the approach to reduce costs is to increase power generating efficiency and lower CO2 emitted per MWh

– This benefits both post-combustion and oxy-combustion.

– Post combustion also requires improved solvents.

• EPRI is increasing its effort in oxy-combustion and is supporting Air Products in demonstrating the ion transfer membrane technology as a more cost-effective alternative to cryogenic separation.


Together…Shaping the Future of Electricity

reducing co2 emissions from coal-fired power plants · •supporting test program for mhi’s...

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