Post on 11-Mar-2020
Systems Overview
Edward S. RubinDepartment of Engineering and Public Policy
Department of Mechanical EngineeringCarnegie Mellon University
Pittsburgh, Pennsylvania
Presentation to the
GCEP Carbon Capture Workshop
Stanford, California
May 26, 2011
How to Reduce the Cost
of Carbon Capture
Edward S. RubinDepartment of Engineering and Public Policy
Department of Mechanical EngineeringCarnegie Mellon University
Pittsburgh, Pennsylvania
Presentation to the
GCEP Carbon Capture Workshop
Stanford, California
May 26, 2011
E.S. Rubin, Carnegie Mellon
Outline of Talk
• Why cost is important
• Where we stand today
• Opportunities for lower-cost systems
• Challenges for lower-cost systems
E.S. Rubin, Carnegie Mellon
Many Ways to Capture CO2
MEA
Caustic
Other
Chemical
Selexol
Rectisol
Other
Physical
Absorption
Alumina
Zeolite
Activated C
Adsorber Beds
Pressure Swing
Temperature Swing
Washing
Regeneration Method
Adsorption Cryogenics
Polyphenyleneoxide
Polydimethylsiloxane
Gas Separation
Polypropelene
Gas Absorption
Ceramic Based
Systems
Membranes Microbial/Algal
Systems
CO2 Separation and Capture
Choice of technology depends strongly on application
E.S. Rubin, Carnegie Mellon
To reduce atmospheric emissions it’s the whole CCS system that matters
Power Plant
or IndustrialProcess
Air or
Oxygen
Carbon-bearing
Fuels
Useful
Products
(Electricity, Fuels,
Chemicals, Hydrogen)
CO2
CO2
Capture &
Compress
CO2
Transport
CO2 Storage
(Sequestration)
- Post-combustion
- Pre-combustion
- Oxyfuel combustion
- Pipeline
- Tanker
- Depleted oil/gas fields
- Deep saline formations
- Unmineable coal seams
- Ocean
- Mineralization
- Reuse
An Integrated Carbon Capture
and Storage (CCS) System
E.S. Rubin, Carnegie Mellon
Post-Combustion Technology for Industrial CO2 Capture
BP Natural Gas Processing Plant(In Salah, Algeria)
Source: IEA GHG, 2008
Examples of Post-CombustionCO2 Capture at U.S. Power Plants
E.S. Rubin, Carnegie Mellon
Warrior Run Power Plant(Cumberland, Maryland, USA)
(So
urc
e: (
IEA
GH
G)
Bellingham Cogeneration Plant(Bellingham, Massachusetts, USA)
(So
urc
e: F
lou
r D
an
iel)
Gas-fired Coal-fired
Source: Vattenfall, 2008
Oxy-Combustion CO2 Capture from a Coal-Fired Boiler
E.S. Rubin, Carnegie Mellon
30 MWt Pilot Plant (~10 MWe) at
Vattenfall Schwarze Pumpe Station (Germany)
Source: Elcano, 2007
Puertollano IGCC Plant (Spain)
E.S. Rubin, Carnegie MellonSource: Nuon, 2009
Buggenhum
IGCC Plant(The Netherlands)
Pre-Combustion Capture at IGCC Plants
CO2 capture
pilot plants
recently built
at IGCC units
in Europe
Coal Gasification to Produce SNG(Beulah, North Dakota, USA)
(So
urc
e: D
ako
ta G
asi
fica
tio
n
Petcoke Gasification to Produce H2
(Coffeyville, Kansas, USA)
(So
urc
e: C
hev
ron
-Tex
aco
)
Examples of Pre-CombustionCO2 Capture Systems
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
CO2 from Energy Use is the Dominant Greenhouse Gas Driving Climate Change
U.S. Greenhouse Gas Emissionsweighted by 100-yr Global Warming Potential (GWP)
Source: USEPA, 2007
7.4%6.5%
83.9%
2.2%
CO2 CH4 N2O Others
84.6%
7.9% 5.5% 2.0%
CO2 CH4 N2O Others
E.S. Rubin, Carnegie Mellon
Leading Candidates for CCS
• Fossil fuel power plants
Pulverized coal combustion (PC)
Natural gas combined cycle (NGCC)
Integrated coal gasification combined cycle (IGCC)
• Other large industrial sources of CO2 such as:
Refineries, fuel processing, and petrochemical plants
Hydrogen and ammonia production plants
Pulp and paper plants
Cement plants
– Main focus is on power plants, the dominant source of CO2 –
Why cost is important
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Multiple Options for Reducing CO2 Emissions
• Reduce demands for energy services and other carbon-emitting activities
• Increase the efficiency of carbon-based energy technologies and systems
• Replace high-carbon energy (e.g., coal-powered electricity) with zero or low-carbon systems
• Capture and sequester CO2 emissions from fossil fuels and biomass
E.S. Rubin, Carnegie Mellon
Cost and Emission Reduction Reqm’t are the Key Determinants of Technology Deployment
Least-cost U.S.
energy mix in 2050
for a GHG policy
scenario of GHGs =
80% below 1990
levels
Results from five
energy-economic
models
0
20
40
60
80
100
120
140
160
2000
AD
AG
E
EPPA
MER
GE
Min
iCA
M
MR
N-N
EEM
EJ/yr
Oil w/o CCS Oil w/CCS Coal w/o CCS
Coal w/CCS Gas w/o CCS Gas w/CCS
Bioenergy w/o CCS Bioenergy w/CCS Nuclear
Non-Biomass Renewable Energy Reduction
80% GHG reduction by 2050
Sourc
e: E
MF
22,
2009
The cost of CCS
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie Mellon
Many Factors Affect CCS Costs
• Choice of Power Plant and CCS Technology
• Process Design and Operating Variables
• Economic and Financial Parameters
• Choice of System Boundaries; e.g.,
One facility vs. multi-plant system (regional, national, global)
GHG gases considered (CO2 only vs. all GHGs)
Power plant only vs. partial or complete life cycle
• Time Frame of Interest
First-of-a-kind plant vs. nth plant
Current technology vs. future systems
Consideration of technological ―learning‖
E.S. Rubin, Carnegie Mellon
Measures of CCS Cost
• Cost of CO2 avoided
• Cost of CO2 captured
• Capital cost
• Dispatch (variable) cost
• Increased cost of electricity (or other product)
E.S. Rubin, Carnegie Mellon
Definition of Key Costs
($/MWh)ccs – ($/MWh)reference
(CO2/MWh)ref – (CO2/MWh)ccs
• Cost of CO2 Avoided ($/ton CO2 avoided)
=
• Cost of Electricity Generation ($/MWh)
(TCC)(FCF) + FOM
(CF)(8760)(MW)+ VOM + (HR)(FC)=
Many factors influence the cost of CCS
E.S. Rubin, Carnegie Mellon
Ten Ways to Reduce CCS Cost (inspired by D. Letterman)
10. Assume high power plant efficiency
9. Assume high-quality fuel properties
8. Assume low fuel price
7. Assume EOR credits for CO2 storage
6. Omit certain capital costs
5. Report $/ton CO2 based on short tons
4. Assume long plant lifetime
3. Assume low interest rate (discount rate)
2. Assume high plant utilization (capacity factor)
1. Assume all of the above !
. . . and we have not yet considered the CCS technology!
E.S. Rubin, Carnegie Mellon
Estimated Cost of New Power Plants with and without CCS
SCPC
IGCC
New
Coal
Plants
20
40
60
80
100
120
Co
st
of
Ele
ctr
icit
y (
$ /
MW
h)
0
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
CO2 Emission Rate (tonnes / MWh)
* 2007 costs for bituminous coals; gas price ≈ $4–7/GJ; 90% capture; aquifer storage
Current
Coal
Plants
PC
NGCC
Natural
Gas
Plants Plants
with
CCS
SCPC
IGCC
NG
CC
E.S. Rubin, Carnegie Mellon
Incremental Cost of CCS for New Coal-Based Plants Using Current Technology
Incremental Cost of CCS relative to same plant type without CCS (based on bituminous coals)
Supercritical Pulverized Coal Plant
Integrated Gasification Combined Cycle Plant
% Increases in capital cost ($/kW)
and generation cost ($/kWh)~ 60–80% ~ 30–50%
Increase in levelized cost for 90% capture
• Capture accounts for most (~80%) of the total cost
• Retrofit of existing plants typically has a higher cost
• Added cost to consumers will be much smaller(reflecting the CCS capacity in the generation mix at any given time)
E.S. Rubin, Carnegie Mellon
Typical Cost of CO2 Avoided(Relative to a SCPC reference plant w/o CCS)
Power Plant System
(relative to a SCPC plant without CCS)
New Supercritical Pulverized Coal
Plant
New Integrated Gasification
Combined Cycle Plant
CCS with deep saline aquifer storage
~ $70 /tCO2 ~ $50 /tCO2
CCS w/ enhanced oil recovery (EOR) storage
Cost reduced by ~ $20–30 /tCO2
Levelized cost in constant US$ per tonne CO2 avoided
Source: Based on IPCC, 2005; Rubin et al, 2007; DOE, 2007
E.S. Rubin, Carnegie Mellon
Cost of CCS for New NGCC Plants (Current Technology)
Cost MeasureNew NGCC
Cost Increase with CCS
% Increase in capital cost ($/kW) ~ 70–100%
% Increase in generation cost ($/kWh) ~ 30–45%
Cost of CO2 Avoided:
Relative to NGCC:
Relative to SCPC:
~$100 /tCO2
~$40 /tCO2
Increase in levelized cost for 90% capture
E.S. Rubin, Carnegie Mellon
High capture energy requirements is a major factor in high CCS costs
Power Plant Type Added fuel input (%)
per net kWh output
Existing subcritical PC ~40%
New supercritical PC 25-30%
New coal gasification (IGCC) 15-20%
New natural gas (NGCC) ~15%
Reducing capture system energy requirements is key to reducing CCS cost
E.S. Rubin, Carnegie Mellon
Breakdown of ―Energy Penalty‖ for CO2 Capture (SCPC and IGCC)
ComponentApprox. % of Total Reqm’t
Thermal Energy ~60%
CO2 Compression ~30%
Pumps, Fans, etc. ~10%
Opportunities for advanced
(lower-cost) capture systems
E.S. Rubin, Carnegie Mellon
28 OFFICE OF FOSSIL ENERGY
Better Capture Technologies Are Emerging
Time to Commercialization
Advanced physical solvents
Advanced chemical solvents
Ammonia
CO2 com-pression
Amine solvents
Physical solvents
Cryogenic oxygen
Chemical looping
OTM boiler
Biological processes
CAR process
Ionic liquids
Metal organic frameworks
Enzymatic membranes
Present
Co
st
Red
ucti
on
Ben
efi
t
5+ years 10+ years 15+ years 20+ years
PBI membranes
Solid sorbents
Membrane systems
ITMs
Biomass co-firing
Post-combustion (existing, new PC)
Pre-combustion (IGCC)
Oxycombustion (new PC)
CO2 compression (all)
E.S. Rubin, Carnegie Mellon
Two Approaches to Estimating Future Technology Costs
• Method 1: Engineering-Economic Analysis
A ―bottom up‖ approach based on engineering
process models, informed by judgments regarding
potential improvements in key process parameters
• Method 2: Use of Historical Experience Curves
A ―top down‖ approach based on application of
mathematical ―learning curves‖ that quantify past
trends for analogous technologies or systems
E.S. Rubin, Carnegie Mellon
Potential Cost Reductions Based on Engineering-Economic Analysis (1)
Source: DOE/NETL, 2006
19% -28%
reductions in
COE w/ CCS
31
28
19
12 10
5 5
0
5
10
15
20
25
30
35
40
% In
crea
se
in
CO
E
A B C D E F G
Latest Analyses for IGCC
7.13(c/kWh)
7.01
(c/kWh)
6.14
(c/kWh)6.03
(c/kWh)
5.75
(c/kWh)
5.75
(c/kWh)
6.52(c/kWh)
SelexolSelexolAdvanced
Selexol
Advanced
Selexol
Advanced
Selexol w/co-
Sequestration
Advanced
Selexol w/co-
Sequestration
Advanced
Selexol w/ITM
& co-Sequestration
Advanced
Selexol w/ITM
& co-Sequestration
WGS Membrane
& Co-Sequestration
WGS Membrane
& Co-Sequestration
WGS Membrane
w/ITM & Co-
Sequestration
WGS Membrane
w/ITM & Co-
Sequestration
Chemical Looping
& Co-
Sequestration
Chemical Looping
& Co-
Sequestration
Pe
rcen
t In
cre
as
e in
CO
E
IGCC
70 69
5550 52
45
22
0
10
20
30
40
50
60
70
80
% I
nc
re
as
e i
n C
OE
A B C D E F G
Cases
`
8.77
(c/kWh)8.72
(c/kWh)
8.00
(c/kWh)7.74
(c/kWh)7.48
(c/kWh)
7.84
(c/kWh)
Latest Analyses for PC Plants
Perc
en
t In
cre
as
e in
CO
E
SC w/Amine
Scrubbing
SC w/Amine
Scrubbing
SC w/Econamine
Scrubbing
SC w/Econamine
Scrubbing
SC w/Ammonia
CO2 Scrubbing
SC w/Ammonia
CO2 Scrubbing
SC w/Multipollutant
Ammonia Scrubbing
(Byproduct Credit)
SC w/Multipollutant
Ammonia Scrubbing
(Byproduct Credit)USC w/Amine
Scrubbing
USC w/Amine
Scrubbing USC w/Advanced
Amine Scrubbing
USC w/Advanced
Amine Scrubbing
6.30
(c/kWh)
RTI Regenerable
Sorbent
RTI Regenerable
Sorbent
PC
50
33
2621
0
10
20
30
40
50
60
% In
crea
se
in
CO
E
A B C D
Cases
`
6.97
(c/kWh)
6.62
(c/kWh)
6.35
(c/kWh)
Latest Analyses for Oxy-Combustion
Perc
en
t In
cre
as
e in
CO
E Advanced
Subcritical Oxyfuel
(Cryogenic ASU)
Advanced
Subcritical Oxyfuel
(Cryogenic ASU)
Advanced
Supercritical Oxyfuel
(Cryogenic ASU)
Advanced
Supercritical Oxyfuel
(Cryogenic ASU)Advanced
Supercritical
Oxyfuel
(ITM O2)
Advanced
Supercritical
Oxyfuel
(ITM O2)
7.86
(c/kWh)
Current State
Supercritical Oxyfuel
(Cryogenic ASU)
Current State
Supercritical Oxyfuel
(Cryogenic ASU) Oxyfuel
E.S. Rubin, Carnegie Mellon
Source: DOE/ NETL, 2010
Potential Cost Reductions Based on Engineering-Economic Analysis (2)
-5
15
35
55
75
95
115
135
155
175
IGCC Today
IGCC w/ CCS Today
IGCC w/ CCS with R&D
Supercritical PC Today
Supercritical PC w/ CCS …
Adv Combustion w/ CCS …
$/M
Wh
($
20
09
)
CCS
with
No
R&D
No
CCS
CCS
with
R&D
CCS
with
No
R&D
No
CCSCCS
with
R&D
Pulverized Coal TechnologiesIGCC Technologies
27% reduction31% reduction
7% below
no CCS
29% above
no CCS
-5
15
35
55
75
95
115
135
155
175
IGCC Today
IGCC w/ CCS Today
IGCC w/ CCS with R&D
Supercritical PC Today
Supercritical PC w/ CCS …
Adv Combustion w/ CCS …
$/M
Wh
($
20
09
)
CCS
with
No
R&D
No
CCS
CCS
with
R&D
CCS
with
No
R&D
No
CCSCCS
with
R&D
Pulverized Coal TechnologiesIGCC Technologies
27% reduction31% reduction-5
15
35
55
75
95
115
135
155
175
IGCC Today
IGCC w/ CCS Today
IGCC w/ CCS with R&D
Supercritical PC Today
Supercritical PC w/ CCS …
Adv Combustion w/ CCS …
$/M
Wh
($
20
09
)
CCS
with
No
R&D
No
CCS
CCS
with
R&D
CCS
with
No
R&D
No
CCSCCS
with
R&D
Pulverized Coal TechnologiesIGCC Technologies
27% reduction31% reduction
7% below
no CCS
29% above
no CCS
Top-down modeling studies also project significant cost reductions
by mid-century, given a policy driver for CCS deployment
Challenges for advanced
(lower-cost) capture systems
E.S. Rubin, Carnegie Mellon
E.S. Rubin, Carnegie MellonSource: DOE/ NETL, 2009
Technical
Challenges and
Research Pathways
for Advanced
Capture Concepts
E.S. Rubin, Carnegie Mellon
Most New Capture Concepts Are Far from Commercial Availability
Source: NASA, 2009
Technology
Readiness Levels
Source: EPRI, 2009
Post-Combustion Capture
E.S. Rubin, Carnegie Mellon
Typical Cost Trend for a New Technology
Research Development Demonstration Deployment Mature TechnologyResearchResearch Development Development DemonstrationDemonstration DeploymentDeployment Mature TechnologyMature Technology
Time or Cumulative Capacity
Ca
pit
al
Co
st
pe
r U
nit
of
Ca
pa
cit
y
Research Development Demonstration Deployment Mature TechnologyResearchResearch Development Development DemonstrationDemonstration DeploymentDeployment Mature TechnologyMature Technology
Time or Cumulative Capacity
Ca
pit
al
Co
st
pe
r U
nit
of
Ca
pa
cit
y
Source: Based on EPRI, 2008
E.S. Rubin, Carnegie Mellon
Most new concepts take decades to commercialize…many never make it
1965 1970 19801975 19901985 1995 20052000
1999: 10 MW
pilot planned
by DOE
1975: DOE
conducts test of
fluidized bed
system
1961:
Process
described by
Bureau of
Mines1973: Used in
commercial refinery
in Japan
1970: Results of
testing published.
1971: Test
conducted in
Netherlands
1967: Pilot-
Scale Testing
begins.
1979: Pilot-scale
testing conducted in
Florida
1984:
Continued pilot
testing with 500
lb/hr feed
1992: DOE
contracts
design and
modeling for
500MW plant
1996: DOE
continues
lifecycle
testing
2002: Paper
published at
NETL
symposium
2006: Most
recent paper
published
1983: Rockwell
contracted to
improve system
Copper Oxide Process
1965 1970 19801975 19901985 1995 20052000
1999:
Process used
at plant in
Poland
1985: Pilots
initiated in U.S.
and Germany1977: Ebara
begins pilot-
scale testing
1998: Process
used in plant
in Chengdu,
China
1970: Ebara
Corporation
begins lab scale
testing.
2005: Process
used in plant in
Hangzhou,
China
2008: Paper on process
presented at WEC forum in
Romania
2002: Process
used in plant in
Beijing, China
Electron Beam Process
1965 1970 19801975 19901985 1995 20052000
1991: Noxso
Corporation
receives DOE
contract
1982: Pilot-
scale tests
carried out in
Kentucky
1985: DOE
conducts
lifecycle testing.
1979:
Development of
process begins
1998: Noxso
Corporation
liquidated. Project
terminated.
1996:
Construction of
full scale test
begins
2000: Noxso
process cited in ACS
paper, Last NOXSO
patent awarded
1997: Noxso
Corporation
declares bankruptcy
1993: Pilot-scale
testing complete
NOXSO Process
Development timelines for
three novel processes for
combined SO2–NOx capture
E.S. Rubin, Carnegie Mellon
Accelerating Innovation in Carbon Capture Requires
• Substantial and sustained support for R&D
• Closer coupling and interaction between R&D performers and technology developers /users
• Better methods to identify promising options, evaluate new processes /concepts, and reduce number and size of pilot and demonstration projects (e.g., via improved simulation methods)
E.S. Rubin, Carnegie Mellon
The DOE Multi-Lab Initiative to Accelerate New Capture Systems
Source: DOE/ NETL, 2011
E.S. Rubin, Carnegie Mellon
IECM: A Tool for Analyzing Power Plant Design Options
• A desktop/laptop computer model developed for DOE/NETL
• Free and publicly available at: www.iecm-online.com
• Provides systematic estimates of
performance, emissions, costs and
uncertainties for preliminary design of:
PC, IGCC and NGCC plants
All flue/fuel gas treatment systems
CO2 capture and storage options (pre- and post-combustion, oxy-combustion; transport, storage)
E.S. Rubin, Carnegie Mellon
Sample IECM Screen Shots
E.S. Rubin, Carnegie Mellon
A Probabilistic Cost Analysis
(Deterministic Case)
FG+
(Deterministic Case)
FG+
Ammonia System(high conc. case)
E.S. Rubin, Carnegie Mellon
• Performance and Cost Models of Advanced CO2 Capture Systems:
– Advanced liquid solvents (Peter Versteeg)
– Solid sorbent systems (Justin Glier)
– Membrane capture systems (Haibo Zhai)
– Advanced oxy-combustion (Kyle Borgert)
– Chemical looping combustion (Hari Mantripragada)
• International Cost Module (Hana Gerbelova)
• Software Development & Dist. (Karen Kietzke)
• Performance and Cost Models of Advanced CO2 Capture Systems:
– Advanced liquid solvents (Peter Versteeg)
– Solid sorbent systems (Justin Glier)
– Membrane capture systems (Haibo Zhai)
– Advanced oxy-combustion (Kyle Borgert)
– Chemical looping combustion (Hari Mantripragada)
• International Cost Module (Hana Gerbelova)
• Software Development & Dist. (Karen Kietzke)
Work in Progress at CMU
E.S. Rubin, Carnegie Mellon
In Summary
• Reducing the cost of carbon capture can enable CCS to play a more prominent role in reducing GHG emissions linked to global climate change
• There are major challenges—but also significant potential—to achieve sizeable cost reductions with advanced technologies
• The pace and direction of technology innovations will depend strongly on sustained support for R&D, and on climate policy drivers that create markets for CCS systems
• Let the games begin!
E.S. Rubin, Carnegie Mellon
Thank You
rubin@cmu.edu