Reducing CO2 Emissions from Coal-Fired

advertisement

Reducing CO

2

Emissions from Coal-Fired Power Plants

CoalFleet for Tomorrow

®

John Wheeldon

([email protected])

EPRI

Advanced Coal Generation

CCTR Advisory Panel Meeting,

Vincennes University,

September 10 th

, 2009

CoalFleet for Tomorrow

®

is a registered service mark of Electric Power Research Institute, Inc.

When CO

2

Capture Included, Higher PC

Efficiency Lowers Levelized Cost-of-Electricity

1.50

1.40

Based on KS-1 solvent, but oxycombustion considered similar

1.30

Pittsburgh #8 PRB

1.20

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

1.10

30 35 40 45

Efficiency of PC plant without CO

2 capture, % (HHV)

Capture only. No allowance for transportation and storage.

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

50

2

Performance Summary: 1300°F USC PC

Subcritical Supercritical 1100 USC 1300 USC

Main stream,

°

F

Main steam, psia

Efficiency, % HHV

Coal flow lb/hr

Flue gas, ACFM

Make-up water, gpm

1005

2600

36.5

840,600

2,107,000

4,260

1080

3800

38.5

797,000

2,016,000

3,750

1120

4000

39.2

782,700

1,982,000

3,650

1256

5100

42.7

718,600

1,823,000

3,310

NO

X

& SO

2

, lb/MWh

CO

2

, lb/MWh from plant

CO

2

, lb/MWh from mining and transportation (*)

0.280

1980

146

0.266

1880

139

0.261

1840

136

0.240

1690

125

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

CO

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

(per MWh) from subcritical unit

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

3

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 CO

2 emissions to 1500 lb/MWh

– Over 40 percent lower than US fleet average.

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

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

4

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% CO

2

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

2 capture capture

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

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

2 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

5

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

CO

2

Post-Combustion Capture (PCC) Plant

Flue Gas Out

(~1.5% CO

2

)

CO

2 to Compressors

(+99.9% purity)

Cooling, power, and solvent make-up

CW

CW

ABSORBER

(~110

°F)

FLUE GAS

COOLER

Flue Gas

(~14% CO

2

)

Rich Amine

Solution

CW

SO

2

POLISHING

WITH CAUSTIC

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

Lean Amine

Solution

STRIPPER

(~250

°F)

Condensate

Steam

6

Power Plant Losses Associated with Post-

Combustion Capture Using Advanced Amine

Efficiency, % HHV lb CO

2

/MWh

Losses, MW (4)

Auxiliary power

Compressors

Steam turbine

TOTAL

% reduction

Efficiency with CCS, % HHV

Percentage point loss

Sub (1)

36.5

1970

9.2

49.5

93.9

152.6

20.3

29.3

7.2

SC (2)

38.2

1880

8.6

47.0

89

144.6

19.3

31.2

7.0

USC (3)

42.5

1690

7.5

41.0

77.9

126.4

16.9

36.9

5.6

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

°F

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

2 capture

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

7

Solvent Used Strongly Influences PCC Plant

Performance

• Need solvents with superior properties

– High CO

2 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 CO

2

Solutions

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

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

8

EPRI Role in Demonstrating Improved Post-

Combustion CO

2

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 CO

2

.

• 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 CO

2 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.

9

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

Power Plant Losses for Different

Percentages of CO

2

Capture

Steam extraction, % (1)

Losses, MW (2)

Auxiliary power

Compressors

Steam turbine

TOTAL

% reduction

CO

2

capture, M-tons/yr

(1) Steam required for solvent regeneration

(2) Net output without CCS = 750 MW

Percent CO

2

capture

90

25

60

17

30

8

9.2

49.5

93.9

152.6

20.3

4.66

6.1

33.0

62.6

101.7

13.5

3.11

3.1

16.5

31.3

50.9

6.8

1.55

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

10

Space and Storage Requirements for CCS

• Space required for

– Capture plant, CO

2 compressors, and added cooling capacity

– Power plant interconnections and maintenance,

– Routing steam piping, flue gas ducting

– Construction activities

– Possible upgrades to SO

2 and NO

X controls

• Space a limiting factor setting achievable percent CO

2 capture

– Riverside plant with FGD may have no space available

• Suitable geological strata to store CO

2 duration EOR or prospects for extended

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

11

Retrofits Require a Lot of Space:

First Come, First Served

CO

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

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

12

EPRI Retrofit Study

Owner:

MidWest

Generation

Location:

Illinois

Owner:

Great River Energy

Location:

North

Dakota

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

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

Owner:

Intermountain

Power

Location:

Utah

Owner:

Nova Scotia

Power

Location:

Nova

Scotia

Owner:

FirstEnergy

Location:

Ohio

13

One Steam Extraction Option

Desuperheater can be replaced by expansion turbine to recoup some of the energy

Thrust balance point At high steam extraction rates thrust bearing design changes required. Below 15 percent design changes not required (~60 percent CO

2 capture)

Source: Imperial College London

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

14

Let-Down Turbine and Condensate Return:

Heat Integration

PCC

System

G

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

15

PC Plant with PCC: Heat Integration

G

PCC

System

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

Heat from CO

2 and CO

2 stripper condenser compressors

16

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 CO

2 emissions at 1100 lb-CO

2

/MWh

(500 kg-CO

2

/MWh )

– Washington state has followed a similar approach

Pulverized Coal Plant = 1760 lb/MWh

(800 kg/MWh)

California Standard = 1100 lb/MWh

(500 kg/MWh)

CTCC = 800 lb/MWh

(360 kg/MWh)

~80% capture required on

CTCC?

CO

2

Pulverized Coal at 90%

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

17

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

Concluding Remarks

• CO

2 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 CO

2 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.

18

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

Together…Shaping the Future of Electricity

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

19

Download