1 Production of Hydrogen and Electricity from Coal with CO 2 Capture Princeton University:Tom Kreutz, Bob Williams, Rob Socolow Politecnico di Milano:Paolo

1

Production of Hydrogen and Electricity

from Coal with CO2 Capture

Princeton University: Tom Kreutz, Bob Williams,Rob Socolow

Politecnico di Milano: Paolo Chiesa, Giovanni Lozza

Presented at the 6th International Conference on Greenhouse Gas Control Technologies (GHGT-6)

September 30-October 4, 2002, Kyoto Japan

2

Princeton UniversityCarbon Mitigation Initiative (CMI)

CMI Carbon Capture Group:• Investigating the H2/Electricity Economy

Activities:

• H2/electricity production from fossil fuels

• H2 (and CO2) distribution

• H2 utilization (e.g. fuel cells, combustion)

• Princeton/Tsinghua collaboration on low emission energy technologies for China

3

Background and Motivation• Distributed energy use (transportation and heating) responsible for

~2/3 of global CO2 emissions

• CO2 capture, compression, dehydration, and pipeline transport from

distributed sources is very expensive.

• Low carbon energy carriers are needed: electricity and hydrogen.

• If CO2 sequestration is viable, fossil fuel decarbonization likely to be

the cheapest route to electricity and hydrogen for many decades.

• Coal is of great interest because it is:

• Plentiful. Resource ~ 500 years (vs. gas/oil: ~100 years).

• Inexpensive. 1-1.5 $/GJ HHV (vs. gas at 2.5+ $/GJ).

• Ubiquitous. Wide geographic distribution (vs. middle east).

• Clean?! Gasification, esp. with sequestration, produces little gaseous emissions and a chemically stable, vitreous ash.

• Example: China: extensive coal resources; little oil and gas. Potential for huge emissions of both criteria pollutants and greenhouse gases.

4

Generic Process: Coal to H2, Electricity, and CO2

• All work presented here is based on O2-blown, entrained flow, coal gasification (e.g. Texaco, E-Gas gasifiers).

GHGT-6 generic process figure (9-25-02)

CO-richraw syngas

H2 product (60 bar)

N2

H2- andCO2-richsyngasQuench +

scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

95%O2

SupercriticalCO2 (150 bar)

Water-gas shift(WGS) reactors

CO + H2O <=> H2 + CO2

CO2drying andcompression

Hydrogencompression

Syngas cleanup,gas separation

Electricityproduction

Heat recovery,steam generation

H2-richsyngas

CO2

Electricpower

5

Process Modeling

• Heat and mass balances (around each system component) calculated using:

• Aspen Plus (commercial software), and

• GS (“Gas-Steam”, Politecnico di Milano)

• Membrane reactor performance calculated via custom Fortran code

• Component capital cost estimates taken from the literature, esp. Holt, et al. and EPRI reports on IGCC

• Benchmarking/calibration:• Economics of IGCC with carbon capture studied by numerous groups

• Used as a point of reference for performance and economics of our system

• Many capital-intensive components are common between IGCC electricity and H2 production systems (both conventional and membrane-based)

6

• Significant variation found in cost values, methodology, and depth of detail.

• Our cost model is a self-consistent set of values from the literature.

• Cost database is evolving; less reliable values removed; range is narrowing.

• Uncertainty shown above leads to an uncertainty of ±10-15% in H2 cost.

0

1

2

3

4

5

6

7

8

9

1 0

1 1

1 2

0 50 100 150 200

Capital Cost (MM$)

Simbeck

Holt

Doctor

Chiesa

Hendriks

Pruden

EPRI3,000-6,000 $/m2

Solids handlingASUO2 compressionGasifier & quenchWGS reactorMembrane reactorRaffinate turbineFGDH2 compressionHRSG, steam turb.CO2 compression

Scale (HHV):1.5 GW th

coal,1 GW th H2

Estimates of Overnight Component Capital Costs

7

Coal price (year 2020 EIA est.) 0.94 $/GJ (HHV)

Capacity factor 80%

Capital charge rate 15% per yr

Balance of plant (BOP) costs 23% of gasifier island (GI) capital

Engineering fees (EF) 15% of (GI+BOP)

Process/project contingency 15% of (GI+BOP+EF)

Plant lifetime* 25 yr

Construction time* 4 yr

Interest during construction (IDC) 16.0% of overnight capital**

O&M costs 4% of overnight capital per year

CO2 sequestration cost 5 $/mt CO2 (~0.5 $/GJ H2 HHV)

U.S. dollars valued in year 2001

Plant scale 1 GWth H2

* Used only in calculating the interest during construction and/or plant internal rate of return** Assuming a 10% real interest rate

Economic Assumptions

8

Benchmark: IGCC Electricity with CO2 Capture

• Cost: 5.6 ¢/kWh, efficiency: 38.4% (HHV). (70 bar gasifier, scale: 406 MWe)

GHGT-6 conv. electricity, CO2 seq. (9-25-02)

Saturatedsteam

CO-richraw syngas

N2 for (NOx control)

H2- andCO2-richsyngas

Heat recoverysteam generator

CO2-leanexhaust

gases

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

95%O2

Steamturbine

Gas turbineAir

Turbineexhaust

SupercriticalCO2 to storage

CO2 drying +compression

High temp.WGS

reactor

Low temp.WGS

reactor

Lean/richsolvent

CO2physical

absorption

Solventregeneration

Lean/richsolvent

H2Sphysical

absorption

Regeneration,Claus, SCOT

H2-richsyngas

Syngasexpander

9

H2 Production: Add H2 Purification/Separation

• Replace syngas expander with PSA and purge gas compressor.

GHGT-6 conv. electricity, CO2 seq. (9-25-02-a)

Saturatedsteam

CO-richraw syngas




CO2-leanexhaust

gases

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

95%O2

Steamturbine

Gas turbineAir

Turbineexhaust



High temp.WGS

reactor

Low temp.WGS

reactor

Lean/richsolvent

CO2physical

absorption

Solventregeneration

Lean/richsolvent

H2Sphysical

absorption


H2-richsyngas

Syngasexpander

10

Conventional H2 Production with CO2 Capture

• H2 cost: 7.1 $/GJ (HHV). (85% HRF, scale: 1 GWth H2 HHV, 3.0 ¢/kWh)

GHGT-6 conv. hydrogen, CO2 seq. (9-25-02)

Saturatedsteam

CO-richraw syngas

High purityH2 product




CO2-leanexhaust

gases

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

95%O2

Steamturbine

Gas turbineAir

Pressureswing

adsorption

Purgegas

Turbineexhaust


High temp.WGS

reactor

Low temp.WGS

reactor

Lean/richsolvent

CO2physical

absorption

Solventregeneration

Lean/richsolvent

H2Sphysical

absorption



11

Capture (and Co-sequester) H2S with CO2

• Remove the traditional acid gas recovery (AGR) unit.

GHGT-6 conv. hydrogen, CO2 seq. (9-25-02-a)

Saturatedsteam

CO-richraw syngas





CO2-leanexhaust

gases

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

95%O2

Steamturbine

Gas turbineAir

Pressureswing

adsorption

Purgegas

Turbineexhaust


High temp.WGS

reactor

Low temp.WGS

reactor

Lean/richsolvent

CO2physical

absorption

Solventregeneration

Lean/richsolvent

H2Sphysical

absorption



12

Conventional H2 Production with CO2/H2S Capture

• Resulting system is simpler and cheaper.

GHGT-6 conv. hydrogen, co-seq. (9-25-02).FH10

Saturatedsteam

CO-richraw syngas



H2- andCO2-rich

syngas


CO2-leanexhaust

gases

High temp.WGS

reactor

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

Low temp.WGS

reactor

CO2/H2Sphysical

absorption

Solventregeneration

Lean/richsolvent

95%O2

Steamturbine

Gas turbineAir

Pressureswing

adsorption

Purgegas

Turbineexhaust

CO2 + H2Sto storage

CO2/H2Sdrying andcompression

13

Conventional H2 with Co-Sequestration of CO2

and Sulfur-bearing Species

• CO2 capture and sequestration lowers efficiency by ~3% and increases H2 cost by ~ 1.5 $/GJ.

(Cost of CO2 pipeline transport and disposal used here is 0.4-0.6 $/GJ.)

• Co-sequestration has potential to lower H2 cost by 0.25-0.75 $/GJ, depending on sulfur content of coal.

0

1

2

3

4

5

6

7

8

Conv. tech. base case

H2

Co

st

($/G

J H

HV

)

CO2 venting Pure CO2 sequestration Co-sequestration

Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost

14

Produce “Fuel Grade” H2 with CO2/H2S Capture

• Remove the PSA and gas turbine; smaller steam cycle.

GHGT-6 conv. hydrogen, co-seq. (9-25-02-a).FH10

Saturatedsteam

CO-richraw syngas



H2- andCO2-rich

syngas


CO2-leanexhaust

gases

High temp.WGS

reactor

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

Low temp.WGS

reactor

CO2/H2Sphysical

absorption

Solventregeneration

Lean/richsolvent

95%O2

Steamturbine

Gas turbineAir

Pressureswing

adsorption

Purgegas

CO2 + H2Sto storage


15

“Fuel Grade” (~93% pure) H2 with CO2/H2S Capture

• Simpler, less expensive plant. No novel technology needed.

GHGT-6 Fuel grade H2, co-seq. (9-25-02)

Saturatedsteam

CO-richraw syngas Low purity

H2 product(~93% pure)

N2

H2- andCO2-rich

syngas


CO2-leanexhaust

gases

High temp.WGS

reactor

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

Low temp.WGS

reactor

CO2/H2Sphysical

absorption

Solventregeneration

Lean/richsolvent

95%O2

Steamturbine

CO2 + H2Sto storage


16

Production of “Fuel Grade” H2

• Reduced H2 purity yields a significant cost savings: 1.0-1.4 $/GJ.

• Fuel grade H2 will be more competitive with gas and oil in the heating sector, and

might be adequate for transportation (H2 ICEVs; barrier to PEM FCEVs?)

0

1

2

3

4

5

6

7

8

Conv. tech. base case Fuel grade H2

H2 C

os

t ($

/GJ

HH

V)



17

Change H2-CO2 Gas Separation Scheme

• Use membrane to separate H2 from the syngas instead of CO2.

GHGT-6 conv. hydrogen, co-seq. (9-25-02-b)

Saturatedsteam

CO-richraw syngas



H2- andCO2-rich

syngas


CO2-leanexhaust

gases

High temp.WGS

reactor

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

Low temp.WGS

reactor

CO2/H2Sphysical

absorption

Solventregeneration

Lean/richsolvent

95%O2

Steamturbine

Gas turbineAir

Pressureswing

adsorption

Purgegas

CO2 + H2Sto storage


18

H2 Separation Membrane Reactor System

• Employ a H2 permeable, thin film (10 m), 60/40% Pd/Cu (sulfur tolerant)

dense metallic membrane, configured as a WGS membrane reactor.

GHGT-6 uncooled turbine, co-seq. (9-25-02)

CO-richraw syngas


N2

H2- andCO2-rich

syngasHigh temp.WGS

reactor

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

95%O2

Hydrogencompressor

Uncooledturbine

MembraneWGS

reactor

O2 (95% pure)

CO2 + SO2to storage

CO2/SO2drying andcompression

Catalyticcombustor

Water

Pure H2

Raffinate

19

Hydrogen Separation Membrane Reactor Concept

Membrane Reactor 4 1-7-02

Porous (optionally asymmetric) ceramic orstainless steel (SS) supporting substrate

Optional oxide layer (needed for metallicmembrane with SS substrate)

Catalyst pellets

Thin film membrane

Entering highpressure syngas

Exiting raffinate

Permeatinghydrogen

High pressure syngas

Shell-tube membrane module

Thin film membrane

Membrane Structure:

Low pressure hydrogen permeate

Porous substrate

Low pressurehydrogen permeate

• Alternative HSMR design: high pressure, WGS reaction, and membrane outside supporting tube, with H2 permeating to the interior of the tube

20

Typical Membrane Reactor Performance

• H2 Recovery Factor (HRF) = H2 recovered / (H2+CO) in syngas

• HRF increases with membrane area diminishing returns

• Membrane costs rise sharply above HRF~80-90% (no sweep gas)

0

5

10

15

20

25

0

20

40

60

80

100

0 5 10 15 20 25 30 35

H2 P

artia

l Pre

ssur

e (b

ar) H

2 Reco

very F

actor (%

)

Membrane Area (103 m2)

® ®

a)

0

10

20

30

40

50

60

70

0

10

20

30

40

50

60

70

0 20 40 60 80 100

Ave

rage

H2 F

lux

(kW

/m2)

Mem

brane M

aterial C

ost ($/kW)

H2 Recovery Factor (%)

®

®

b)

10 m thick Pd-40Cu membrane475 C; 1000 ppm H

2S; 67 bar syngas

21

System Parameter Variations

System Performance:- membrane reactor configuration

- membrane reactor operating temperature

- gasifier/system pressure

- hydrogen purity

- hydrogen backpressure

- hydrogen recovery factor (HRF)

- raffinate turbine technology (blade cooling vs. uncooled)

System Economics:- membrane reactor cost (and type)- by-product electricity value

- sulfur capture vs. sulfur + CO2 co-sequestration

22

Pd/Cu Membrane-Based H2 Separation

• Cost of H2 via Pd/Cu membrane very close to conventional technology.

0

1

2

3

4

5

6

7

8

Conv. tech. base case Fuel grade H2 Membrane base case

H2 C

os

t ($

/GJ

HH

V)



est.

23

Oak Ridge Molecular Sieving Membrane- H2 Permeance Relative to 60/40 Pd/Cu -

0

10

20

30

40

50

60

70

1 10 100 1000

Upstream Pressure (bar)

H2 P

erm

eanc

e R

atio Hydrogen

backpressure(bar):

0

12

5

10

20

50

• Membrane permeance pressure dependence:

- ceramic: (Phigh – Plow) vs. metallic: (√Phigh – √Plow)

• Permeance increase up to factor of ~50 possible. Reduced purity.

24

• Preliminary economic comparison, using same membrane cost ($3,000/m2): H2 cost lower by ~0.5 $/GJ HHV (at

70 bar; more for 120 bar gasifier).

Ceramic Molecular Sieving Membrane

0

1

2

3

4

5

6

7

8

Conv. tech. basecase

Fuel grade H2 Membrane basecase

High permmembrane

H2

Co

st

($/G

J H

HV

)CO2 venting Pure CO2 sequestration Co-sequestration


est.est.

25

Conclusions

• Consistent framework for estimating the performance and cost of converting coal to H2 and electricity with CO2 sequestration.

• Investigated membrane-based vs. conventional H2 separation.

• Parametric investigation of membrane systems shows:

– H2 cost via 60/40 Pd/Cu membrane is comparable to that via conventional technology.

– High permeance microporous membranes offer modest cost reductions (~$0.6/GJ HHV), but with reduced H2 purity.

• High H2 purity is costly; “fuel grade” H2 can be produced with conventional technology at significantly lower cost (1.0-1.4 $/GJ).

• Co-sequestration lowers the cost of H2 (0.25-0.75 $/GJ HHV), and may provide other environmental benefits (Hg, etc.).

• We plan to extend methodology to study other feedstocks (petroleum residuals, natural gas, etc.) and novel technologies.

26

Back-up Slides...

27

Example of Disaggregated Cost of H2 Production system

(membrane system...change to conventional)...drop slide?

• 70 bar gasifier, 85% HRF, uncooled raffinate turbine, scale: 1 GWth H2 (HHV)

-1

0

1

2

3

4

5

6

7

Hyd

roge

n C

ost

($/G

J, H

HV

)CO2 Sequestration (5 $/mt CO2)

CO2 drying & compression

H2 compressor

Raffinate turbine

Membrane reactor

H.T. WGS reactor

Gasifier and quench

O2 separation & compression

Coal preparation & handling

Construction Interest (4 yr)

O&M (4% per year)

Coal (0.93 $/GJ, HHV)

Electricity credit (5.54 ¢/kWh)

Fig. D3Net cost: 6.6 $/GJ

Capital Charge Rate=15%

28

Membrane System with Cooled Raffinate Turbine

• Blade cooling enables higher TIT (1250 C vs. 850 C), and higher electrical conversion efficiency for raffinate stream. Requires much lower HRF (~60%).

GHGT-6 cooled turbine, co-seq. (9-25-02)

CO-richraw syngas


N2

H2- andCO2-rich

syngasHigh temp.WGS

reactor

Quench +scrubber

Air Airseparation

unit

Coalslurry O2-blown

coalgasifier

95%O2

Hydrogencompressor

Cooledturbine

MembraneWGS

reactor

O2 (95% pure) CO2 + SO2to storage

CO2/SO2drying andcompression

Catalyticcombustor

Water

Pure H2

RaffinateSteam(for bladecooling)

Steam(for bladecooling)

Uncooledexpander

29

• Cooled turbine (low HRF) system has poor overall efficiency and economics (at low co-product

electricity prices, 3 c/kWh)

0

1

2

3

4

5

6

7

8

9

Conv. tech. basecase

Fuel grade H2 Membrane basecase

Cooled raf.turbine

H2

Co

st

($/G

J H

HV

)CO2 venting Pure CO2 sequestration Co-sequestration


est. est.

Membrane System with Cooled Raffinate Turbine

30

The Case for Hydrogen

~1/3 Central station electricityCentralized(large scale)

~1/3 Transportation Distributed

~1/3 Other (industrial & residential heating)

Distributed

• Stabilizing atmospheric CO2 at e.g. 500 ppmv will require deep

reductions, probably in all 3 sectors.

• Capture, compression, dehydration, and pipeline transport of CO2 from

distributed sources is extremely expensive.

• Distributed energy consumption with low CO2 emissions requires low

carbon energy carriers, electricity and hydrogen.

• H2 likely to play a key role in both the transportation and heating

sectors. Relative to electricity:

• Higher overall efficiency of production & use

• Easier (less costly) storage

31

The Case for Coal

• Abundance of low quality feedstocks (coal, heavy oils, tar sands, etc.) relative to conventional oil and natural gas

• Low feedstock cost relative to natural gas

• China is dependent on coal; US expected to continue being large coal user is near-zero emission option for coal feasible?

• Air pollution concerns likely to drive coal gasification for power generation—springboard for producing H2 from coal

• Sulfur, other criteria pollutants, toxics (e.g, Hg) pose major challenges in H2/electricity manufacture; gasification facilitates low emissions

• Residual environmental, health, and safety issues of coal mining and other low-quality feedstocks

32

Some Interesting Results

Description CO2 ventingPure CO2

sequestrationCO2-S

Co-seq.

eff (%) $/GJ eff (%) $/GJ $/GJ

Conv. Tech.

Base case 71.6 5.6 69.4 7.1 6.8

Fuel grade H2 75.5 4.8 74.7 6.1 5.8

HSMR-Based System

Base case 75 5.3 69.1 7.2 7.0

Cooled raf. turbine 66 4.9 57.8 8.5 8.1

High perm HSMR 76 4.7 69.9 6.6 6.4

• Sequestration lowers efficiency and increases costs• Co-sequestration has potential to lower costs

• H2 purity comes at a significant cost. Fuel grade (~94% H2) can be produced at a significantly lower cost in a system with significantly lower capital cost.

• 60/40% Pd/Cu membrane system not obviously better than conventional.• Cooled turbine (low HRF) system has poor efficiency and economics (at low co-

product electricity prices, 3 c/kWh)• High permeance membrane (at 70 bar) might yield only modest improvements.

33

Effect of HSMR Configuration

• In this system, with an upstream WGS reactor, a membrane reactor not obviously necessary for good system performance.

0

10

20

30

40

50

60

70

0 20 40 60 80 100


Avg

. H

2 F

lux

(kW

/m2,

HH

V)

0

20

40

60

80

100

120

140

HS

MR

Co

st ($/kW

HH

V)HT-WGS+HSMR

HT-WGS+HSM

HSMR

34

• Increasing pressure can significantly reduce cost of decarbonized hydrogen

• Cooled raffinate turbine typically requires low HRF to realize high TIT

• Uncooled turbine/high H2 recovery: greater promise, esp. at low elec. prices

Hydrogen Cost vs Gasifier Pressure

6.0

6.5

7.0

7.5

8.0

8.5

40 50 60 70 80 90 100 110 120 130

Gasifier Pressure (bar)

Hyd

roge

n C

ost

($/G

J H

HV

)

Fig. H2

85% HRF

75% HRF

5.5

4.0

3.6

3.0

ElectricityPrice

(¢/kWh):

Lines:Cooled turbineat ~60% HRF

Single pointsat 70 bar:uncooled turbine

35

Cost of H2 Compression and HSMR

vs. H2 Backpressure

• Broad cost minimum seen here (not always) at low H2 backpressure

0.0

0.5

1.0

1.5

2.0

0 1 2 3 4 5

H2 Backpressure (bar)

Cos

t ($

/GJ

H2,

HH

V)

Fig. G4b

Sum

Membrane capital

Compressorpower

Compressorcapital4

3

Number of compressor

stages:

Cost Minimum

36

Effects of H2 Recovery and Electricity Price

• Efficiency rises monotonically with increasing HRF• Low prices for co-product electricity favors production of H2 over electricity

• At high electricity prices, H2 cost is insensitive to HRF in the 60-90% range

0

20

40

60

80

40 50 60 70 80 90


Effe

ctiv

e E

ffici

ency

(%

, HH

V)

6

7

8

9

10

Hydrogen C

ost ($/GJ, H

HV

)

Fig. A4e

3.0

5.8

Electricityprice

(¢/kWh):

5.5

37

Effects of H2 Recovery Factor and HSMR Cost

• A five-fold variation in HSMR cost alters the H2 cost by ~$1/GJ (HHV)

• H2 costs exhibit a broad minimum with respect to HRF (from ~60-90%)

• As HSMR costs decrease, optimal HRF increases (long green arrow)

5

6

7

8

9

40 50 60 70 80 90


Hyd

rog

en

Co

st (

$/G

J, H

HV

)

0

5

10

15

20

Hydrogen-to-E

lectricity Ratio

Fig. Ab

10,000

1,000

3,000

5,000

HSMR cost

($/m2):

Scale: 1 GWth H2 at 85% HRF

Electricity: 5.54 ¢/kWh (50 $/tC)

38

• 3.6 ¢/kWh: electricity from GTCC fired by natural gas (cost: 3.4 $/GJ HHV)

• 5.5 ¢/kWh: breakeven price for electricity from coal IGCC - at carbon tax of $50/tC - when CO2 sequestration becomes competitive with CO2 venting

Effects of Electricity Price and Turbine Technology

5.0

6.0

7.0

8.0

9.0

10.0

2 3 4 5 6 7

Electricity Price (¢/kWh)

Hyd

roge

n C

ost

($/G

J H

HV

)

Fig. O

Scale: 1.5 GW th coal

(= 1 GWth H2at 85% HRF)70 bar gasifier

Uncooled raffinate turbine75% H2 recovery

Uncooled raffinate turbine85% H2 recovery

Cooled raffinate turbine59% H2 recovery

3.6 5.5

Documents

1 Production of Hydrogen and Electricity from Coal with CO 2 Capture Princeton University:Tom Kreutz, Bob Williams, Rob Socolow Politecnico di Milano:Paolo