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Carbon Capture & Storage
What & Why
Rae Cronmiller, Environmental Counsel
NRECA
CCS is not an existing emissions control
CCS: A system of many on and offsite components
Why Now?
•
•
•
April 2012 EPA NSPS Proposed Rule
Identified “best system of emission reduction”
(BSER) for coal and natural gas base-load
generation as Natural Gas Combined Cycle
Refused to identify any BSER for coal
September 2013 EPA NSPS Proposed Rule
Based on cost, feasibility, emission reduction
and technology, partial CCS is BSER
Status of Technology for CO2 Capture & Storage
Dr. Jeffrey N. Phillips
Senior Program Manager
Washington, DC
September 30, 2013
Key Takeaways
• CO2 capture and storage (CCS) has been tested for about
a year at small scale in fossil fuel power plants, and over
longer times at larger scale in non-power applications
• Most of the experience with CO2 storage involves
enhanced oil recovery (EOR) projects
– Storage in deep saline formations has different
challenges and less experience
• No insurmountable technical hurdles have been uncovered,
but high costs limit deployment
DOE, EPRI and others are working to bring down costs
but it will take time and sustained R&D
© 2013 Electric Power Research Institute, Inc. All rights reserved.
6
Largest CO2 Capture System Ever Operated on a
Coal Power Plant
• 400,000 ton/yr CO2 from 100 MW Lubbock Power & Light
power plant
• Operational 1983-1984 for EOR Floods
• Dow Amine Technology
Photo courtesy Gas Processing Solutions LLC
© 2013 Electric Power Research Institute, Inc. All rights reserved.
7
CO2 Capture System on a Natural Gas
Combined Cycle Plant – Bellingham, Mass.
Photo from Google Maps
Tanks for storing liquid CO2
Fin-fan coolers for
capture system
CO2 absorber vent
Exhaust duct going to
capture system
Combined exhaust
stack for two W501D
gas turbines
Captured ~100,000 tons/year for carbonated beverages
– no longer in operation
© 2013 Electric Power Research Institute, Inc. All rights reserved.
8
AEP-Alstom CCS Demo
Project Overview
• Alstom’s chilled ammonia CO2
post-combustion capture
– ~20-MWe demonstration at AEP’s
Mountaineer Plant in WV
Alstom’s Chilled Ammonia Process at AEP’s Mountaineer
– Designed for ~100,000
Property of Alstom Power and/or AEP
tons-CO2/year
– Injection occurred in saline reservoir using two on-site wells
– Capture started in September 2009 and storage in October 2009;
~57,000 tons were captured and ~42,000 tons stored
– Capture project was completed in May 2011
– Location of the injected CO2 continues to be monitored per AEP’s
injection permit
Power consumption was 22% less than generic amine technology
© 2013 Electric Power Research Institute, Inc. All rights reserved.
9
Southern-MHI CCS Demo
Project Overview
• MHI KM-CDR advanced amine CO2
combustion capture
post-
– ~25-MWe demonstration at Alabama
Power’s
Plant Barry in AL
MHI’s KM-CDR Process at Plant Barry
– ~150,000 tons-CO2/year
Property of MHI and/or Southern
– Capture started on June 3, 2011; over 200,000 tons captured so far
– Injection is occurring in the Citronelle dome ~10 miles away and
started on August 20, 2012; over 83,000 tons stored so far
– Plan is to continue capturing CO2 through 2014 with the goal to store
at least 100,000 tons in geologic sequestration
– Monitoring of the CO2 will continue after injection ceases
– Storage project is part of US DOE’s Regional Sequestration Program
Currently only coal power plant in the world capturing & storing CO2
© 2013 Electric Power Research Institute, Inc. All rights reserved.
10
Key Lessons Learned from Demos to Date
• Even best technologies which have been tested would
be very expensive to implement at commercial scale
– A 235 MW follow-on to the Mountaineer demo was
estimated by AEP to cost $1.065 billion ($4500/kW)
• Permitting for CO2 storage could be a lengthy process
– The regulating authority needs to learn about the
technology before it will be comfortable in permitting it
• Integrated operation of CO2 capture, transportation and
storage at 20-25 MW scale has revealed no
insurmountable technical barriers
© 2013 Electric Power Research Institute, Inc. All rights reserved.
11
CO2 “Capture-to-Storage” Projects in Operation
SECARB
Map courtesy Global CCS Institute (with additions by EPRI)
~10 projects worldwide – SECARB is only one at a power plant
© 2013 Electric Power Research Institute, Inc. All rights reserved.
12
Large-scale CCS projects operating in North
America
1. Weyburn EOR – CO2 from
coal gasifier in ND, 2.8
million ton/yr
Map & data from Global CCS Institute
2. Shute Creek EOR – CO2
from natural gas
processing, 7 million ton/yr
1
3. Enid EOR – CO2 from
fertilizer production, 0.7
million ton/yr
2
5
4
3
4. Val Verde EOR – CO2 from
nat. gas processing, 1
million ton/yr
6
5. Century Plant EOR – CO2
from nat. gas processing, 8
million ton/yr
A new 650 MW coal power plant
would need to capture ~1.8 million
tons CO2 per year to meet NSPS
© 2013 Electric Power Research Institute, Inc. All rights reserved.
13
6. Port Arthur EOR – CO2
from steam methane
reformer (US DOE project),
1 million ton/yr
Starting up in 2014
• Boundary Dam:
90% CO2 capture
retrofitted to 150 MW
coal power plant, ~1
million tons CO2 per
year for EOR
Map from Global CCS Institute
Boundary
Dam
• Kemper County:
new 582 MW IGCC
with ~65% CO2
capture, ~3 million
tons CO2 per year
for EOR
Kemper
Both receiving large government subsidies. Will give power
industry “real life” experience in operating large-scale CCS
© 2013 Electric Power Research Institute, Inc. All rights reserved.
14
Saline Storage or Enhanced Oil Recovery (EOR)?
• EOR: Injected CO2 pushes oil
out
•Saline: Injected CO2 pushes
saline to the side
•EOR: Geology already wellknown because of many years of
oil production
•Saline: Geology typically not
well-known
Could take 3-5 years and
approx. $50 million to
characterize a saline formation
for CO2 storage – and result
could be it is not a good site
Graphic from DOE CO2 Atlas
© 2013 Electric Power Research Institute, Inc. All rights reserved.
15
Enhanced Oil Recovery
• The red regions from DOE’s CO2 Atlas show oil fields with
potential for CO2 enhanced oil recovery (EOR)
Map from US DOE NATCARB website
Current US CO2
Pipeline Network
EOR not located everywhere we will need power plants
© 2013 Electric Power Research Institute, Inc. All rights reserved.
16
U.S. Saline Formations
• The U.S. Department of Energy has conducted a
preliminary assessment of U.S. geology
Map from US DOE NATCARB website
© 2013 Electric Power Research Institute, Inc. All rights reserved.
17
Critical Challenges
• Reducing capture energy penalty and
equipment costs
– There is much potential for improvement
• Demonstrating CO2 storage capacity &
permanence
• Lack of economic driver for implementing
CO2 Capture and Storage
This is a marathon and the race has only begun.
© 2013 Electric Power Research Institute, Inc. All rights reserved.
18
Together…Shaping the Future of Electricity
© 2013 Electric Power Research Institute, Inc. All rights reserved.
19
The Status of Carbon Capture and Storage
Congressional Staff Briefing
September 30, 2013
Kemper County IGCC
Brian D. Toth
R&D Portfolio: Carbon Capture and Storage
University Training Program
Biomineralization Study
National Carbon Capture Center
1 MW Solid Sorbent Pilot
Geologic Suitability Study
Coal Seam Injection Study
Kemper County IGCC
Underground Carbon Injection
Groundwater Impacts Study
Pilot Capture Demo
25 MW CCS
UAB Cap Rock Lab
R&D Portfolio: Carbon Capture and Storage
University Training Program
Biomineralization Study
National Carbon Capture Center
1 MW Solid Sorbent Pilot
Geologic Suitability Study
Coal Seam Injection Study
Kemper County IGCC
Underground Carbon Injection
Groundwater Impacts Study
Pilot Capture Demo
25 MW CCS
UAB Cap Rock Lab
Kemper County IGCC
Kemper County IGCC
21st Century Technology
•
15+ years of development at the NCCC
•
582 MW
•
Integrated Gasification Combined Cycle
•
Fuel: Mississippi Lignite, ~4 million tons/year
•
CO2 Capture: at least 65% - to be used for
Enhanced Oil Recovery (EOR)
• Zero Liquid Discharge (ZLD) plus treated effluent
from City of Meridian, MS and moisture from coal
drying as makeup water
•
Construction jobs: ~12,000 direct/indirect
•
Permanent jobs: ~1,000 direct/indirect
Plant Site
CCS Legal and Regulatory Issues
Congressional Staff Briefing, September 30, 2013
Fred Eames
Partner
Hunton & Williams LLP
Insert
image here
General Topics
• Legal issues with development of facilities for
geologic sequestration
• Regulatory structure and issues for geologic
sequestration facilities
• Liability issues for geologic sequestration
28
Legal Issues with Geologic
Sequestration Facility Development
• Aggregation of pore space rights
• Infrastructure development issues
29
Map of Possible CO2 Pipeline Corridors for
High CCS Case with Greater Use of EOR
Source: Current State and Future Direction of Coal-Fired Power in the
Eastern Interconnection, EISPC, June 2013
http://naruc.org/Grants/Documents/Final-ICF-ProjectReport071213.pdf
30
North America CO2 Geologic Potential by State
Source: Current State and Future Direction of Coal-Fired Power in the
Eastern Interconnection, EISPC, June 2013
http://naruc.org/Grants/Documents/Final-ICF-ProjectReport071213.pdf
31
North America CO2 Geologic Potential by State
(Continued)
Source: Current State and Future Direction of Coal-Fired Power in
the Eastern Interconnection, EISPC, June 2013
http://naruc.org/Grants/Documents/Final-ICF-ProjectReport071213.pdf
32
Existing Fossil Generation & Optimal CCS Locations
Without Any Drinking Water Resources Location
Analysis
Note: Optimal Locations are for new plants, not retrofit of existing power plants
Source of Map: NatCarb Atlas; Overlay: APPA Optimal Location Criteria Maps
without CO2 pipelines
33
Proposed Rule Should Address Legal &
Commercial Obstacles to CO2 injection
• Local laws banning or limiting fracking or similar drilling practices (Best
Management Practices) for CO2 injection
• Anti-fracking ordinances
• Safe Drinking Water Act and 22 state drinking water laws (see Gablehouse paper)
• Resources Conservation and Recovery Act (RCRA) “like kind waste” exemption
for oil & gas does not apply to power sector for injecting acid gas
• Is CO2 an acid gas subject to Comprehensive Environmental Response,
Compensation, and Liability Act (CERCLA) litigation?
• Who owns and pays for the CO2 monitoring requirements 100 years after the
power plant closes under Underground Injection Control (UIC) program?
• What is financial assurance or insurance posted under UIC program for CO2
injected for 100 years after power plant closes? How does this affect bond ratings?
34
Proposed Rule Should Address Legal &
Commercial Obstacles to CO2 injection
• Not all states pool or unitize for oil/gas extraction or CO2 injection
• Many states have no distinction between surface and subsurface space and
surface owner decides
• What happens 10 years into CO2 injection—can a new surface owner oppose
and stop the project?
• Pore space may not be recognized in all states for CO2 injection
• Not all state laws allow for the use of surface water for CO2 injection/water
lubrication (farmers/cattlemen)
• Not all banks/mortgage companies allow oil and gas leases beneath
residential areas—why will CO2 be more promising?
35
APPA CCS White Papers
• Retrofitting Carbon Capture Systems on Existing Coal-Fired Power Plants
• Will Water Issues/Regulatory Capacity Allow or Prevent Geologic
Sequestration for New Power Plants? A Review of the Underground
Injection Control Program and Carbon Capture and Storage
• Carbon Capture and Storage From Coal-Based Power Plants
• Parasitic Power for Carbon Capture
• Geologic CO2 Issue Spotting and Analysis
• Carbon Capture and Sequestration Legal and Environmental Challenges
Ahead
Available online at: http://www.publicpower.org/files/HTM/ccs.html
36
Two Matters Must Be Resolved before Coal-Fired
Plants with CCS Are Commercially Demonstrated or
Finalized
1. Is CO2 as an acid-gas a CERCLA (Superfund)
pollutant?1
2. How long would monitoring be required after
the power plant closes?
1 EISPC
Report, June 2013, Page 179
37
Contact Info
Theresa Pugh
Director of Environmental Services
[email protected] / 202-467/2943
Desmarie Waterhouse
Director of Government Relations and Counsel
[email protected] / 202-467/2930
38
Regulatory Structure for Geologic
Sequestration Facilities
• Safe Drinking Water Act Underground Injection Control (UIC)
Program
– GS: New Class VI UIC program
– Purpose of UIC program: prevent “endangerment” of
USDWs
– More stringent requirements than any other well class
except Class I hazardous waste disposal
– Basics:
• Injection zone sufficient to hold the volume; confining zone free
of faults/fractures
• Protective construction, operating, maintenance requirements
• Financial assurance requirements (surety, insurance, etc.)
• 50-year default post-injection site care
39
Liability Issues
• Liability may arise via statute or common law
• Applicable/potentially applicable federal statutes
– Safe Drinking Water Act (UIC program)
– Resource Conservation and Recovery Act
– CERCLA (Superfund)
• State laws
• Potentially applicable common law theories
– Negligence or strict liability
– Trespass
– Nuisance
40
RCRA and CERCLA
• RCRA
– Could CO2 injectate be considered a “hazardous
waste?” How?
– EPA proposed conditional exclusion
• CERCLA
– Could CO2 injectate be considered a “hazardous
substance,” or could mobilized materials be
considered a “release?”
• 107(j) federally permitted release exemption
– Potential “upstream” liability consequences
41
Common Law
• Negligence – Breaching a duty of ordinary care
• Strict liability – Incident = liability, even when
taking perfect care
• Trespass – Unlawful interference with
possessory rights that causes harm
• Nuisance – Non-trespassory, substantial
interference with the enjoyment of property
42
Unique Legal Issues
• Long-term (post-closure) liability
– Length of mobile phase may differ by formation
– Volumes, other circumstances differ from other
industrial activities
• “Triple threat” confluence of regulation
– Obligation to serve customers
– Air regulations limiting emission to atmosphere
– UIC regulations prohibiting endangerment of
USDW
43
Costs and Incentives for coalfueled power plants with CCS
Congressional Staff Briefing
September 30, 2013
Ben Yamagata
Coal Utilization Research Council (CURC)
CURC’s June, 2012 comments on the EPA’s
Proposed Rule for New Coal-fueled Power Plants
 Commenting upon the impact of the proposed rule, CURC stated:
• “The impact of this proposal is nothing less than to stop the development of new
coal technology, deployment of coal-based capacity in the United States, and
frustrate efforts to commercialize carbon capture utilization and storage (CCUS)
technology.”
•
EPA argues that the CCS requirement on new coal-fueled power plants will serve as a
“technology driver”
•
CURC continues to believe that the re-proposed rule will operate to –
• Stop coal related technology development
• Dissuade deployment of new coal capacity
• Frustrate any attempts to further commercialize CCUS
The re-proposed rule will not serve as a “technology driver”
From DOE’s Clean Coal Research Program :
Carbon Capture Technology Program Plan ,
January, 2013, page 10
“… . There
commercially
available 1st-Generation
capture
notare
ready
for implementation
onCO2
coaltechnologies that are currently being used in various industrial
based
power
plants
because
they havethese
applications.
However,
in their
current
state of development
technologies
are not demonstrated
ready for implementation
on coal-based power
not been
at appropriate
plants because they have not been demonstrated at appropriate
scale, require approximately one-third of
scale, require approximately one-third of the plant’s steam and
plant’s
and power
to operate,
power the
to operate,
and steam
are very expensive.
For example,
DOE/NETL
estimates
thatare
the very
deployment
of a current 1st-Generation postand
expensive.
combustion CO2 capture technology—chemical absorption with
anaqueous monoethanolamine solution—on a new PC power plant
would increase the COE by ≈80 percent and derate the plant’s net
generating capacity by as much as 30 percent. .…”
These data are based on the EIA’s
most recent Annual Energy Outlook.
They show which systems are
“capital intensive” (coal, nuclear),
versus “fuel intensive” (gas); and the
impact of adding current CCS
technologies.
Clearly, if coal is to play a role in a carbon
constrained world, the cost of CCS
technologies must be greatly reduced.
Major U.S./Canada Demonstrations
Using Existing Infrastructure, Creating New Markets
CCPI
“Learning
first-generation
CO Capture from Ethanol Plant
Post Combustion
CO Capture & EOR by doing”  scaling
ICCS Areaup
1
CO Stored in Saline Reservoir
~$1.24B Total; ~$240 M Canada Gov’t
$208M Total; $141M DOE
FutureGen
2.0
EOR – 1.0M
TPY 2014 start
technologies
SALINE – ~1 M TPY 2013 start
International Project
Evidence
of
CCS
w/EOR
opportunities
 viable
FutureGen 2.0
Large-Scale Testing of Oxy-Combustion w/ CO Capture
business case
& Sequestration in Saline Formation
~$1.3B Total; ~$1.0B DOE
CCS MVA best practices
SALINE –Validate
1.3M TPY 2016 start
SaskPower Boundary Dam
Archer Daniels Midland
2
2
2
2
Summit TX Clean Energy
Southern Company
However . . .
Kemper County IGCC Project
IGCC-Transport Gasifier
w/Carbon Capture
• First-generation capture technologies  energy
~$2.67B Total; $270M DOE
penalty ~30% and > $100/tonne CO2 captured EOR – 3 M TPY 2014 start
Hydrogen Energy
California
• Requires government subsidies $$$ + polygeneration
Commercial Demo of Advanced
IGCC w/ Full Carbon Capture
+ chemicals) + EOR
~$4B Total; $408M(power
DOE
Leucadia Energy
Commercial Demo of Advanced
IGCC w/ Full Carbon Capture
~$1.7B Total; $450M DOE
EOR – 3M TPY 2014 start
EOR – 3M TPY 2018 start
NRG
W.A. Parish Generating Station
Post Combustion CO2 Capture
$339M Total; $167M DOE
EOR – 1.4M TPY 2014 start
Air Products and Chemicals, Inc.
CO2 Capture from Steam Methane Reformers
EOR in Eastern TX Oilfields
$431M – Total, $284M – DOE
EOR – 1M TPY 2013 start
CO2 Capture from Methanol Plant
EOR in Eastern TX Oilfields
$436M - Total, $261M – DOE
EOR – 4.5 M TPY 2015 start
EIA’s Projection: Modest to No new
Coal Through 2040
Historic
Forecast
Source: DOE/NETL Historic Data: Ventyx Velocity Suite; Forecasted Data: EIA AEO 2013
DOE has similar RD&D programs
for retrofitting existing units and
for gasification (e.g. IGCC)
Commercial availability for next
generation (lower costs) systems
may be too late
Source: Clean Coal Research Program U.S. DOE/ Office of Fossil Energy, Carbon Capture Technology Program Plan ,January, 2013
President & Congress Coal Budgets
450
400
350
millions $
300
250
200
President's Request
150
Annual funding levels
called for in the
CURC/EPRI Technology
Roadmap
Expect decreasing coal
R&D budgets as overall
spending by the federal
government decreases
and coal is perceived to
be of lesser importance
as a needed energy
options in the U.S.
Enacted by Congress
FY 2014
100
50
0
FY08
FY09
FY10
FY11
FY12
FY13
FY14
Senate $268M
House ~$ 295 M
EPA’s Rationale for Requiring partial CCS
on new coal power plants
EPA’s Rationale
 Four DOE (and Canadian)
supported CCS coal power
plant demonstrations so
technology “adequately
demonstrated”
 No new coal builds for
several decades
 Regulation will serve as a
“technology driver”
Questions about the Rationale
 Demonstrations are heavily
subsidized
 No certainty that all
demonstrations will be
undertaken
 Inadequate R&D funding
support, no plans to support
any further 1st generation
projects,
 What happens when there is
no near term market?
• The R&D pipeline dries up
3-Part Technology Program taking Coal from 2013 to 2050+
Efficiency, reliability,
flexibility of the
Near- term program –
existing coal fleet
Support coal-fueled facilities
(CTL, SNG, chemicals,
electricity) that capture CO2 to
recover crude oil
Incentivize the construction of
10GW advanced coal power
plants that will install CCS when
commercially available
Improve today’s coal-use
technologies ( target costs &
performance)
Develop “transformational”
technologies (create new ways to
use coal)
2013
2025
Mid-term program
Longer term program
2050
Brief Review of the 3-Part Program
 Coal’s contribution to the “all of the above” and a
part of the clean energy future of the U.S.
 A program that recommends technology
applications from 2013 to 2050 and beyond
 Near-term technology for existing coal plants
 Mid-term construction of advanced coal plants and coalfueled plants that capture and sell CO2 for enhanced oil
recovery
 Longer-term RD&D technology programs to use our vast,
domestic energy resource – coal
Thank you
Contact information:
Ben Yamagta
202-298-1800
www.coal.org