Secarb Plant Barry CCS Project: Sharing Knowledge & Learning - Presentation by Dr Gerald Hill for UKCCSRC seminar, 19 September 2014, Edinburgh

1. Southeast Regional Carbon Sequestration
Partnership
“SECARB PLANT BARRY CCS PROJECT:
Sharing Knowledge & Learning”
CCS Seminar
UKCCSRC
University of Edinburgh
19 September 2014
Gerald R. Hill, Ph.D.
Senior Technical Advisor
Southern States Energy Board

2. Acknowledgements
 This material is based upon work supported by the U.S.
Department of Energy National Energy Technology Laboratory.
 Cost share and research support provided by SECARB/SSEB
Carbon Management Partners.
 Anthropogenic Test CO2 Capture Unit funded separately by
Southern Company and partners.
2

3. Presentation Outline
 Overview of U.S. CCS/CCUS Projects
 SECARB Integrated Anthropogenic
Test
– Plant Barry Capture Unit
– Dedicated CO2 Pipeline
– Characterization of the Injection Site
– Injection & Monitoring Systems
– Project Risk Assessment
– Public Outreach and Education
 Responding to New Realities
3

4. National Carbon Capture Center
• Flexible testing facility where new processes can be
tested on both coal derived syngas and flue gas at
various scales.
• A technology development facilitator by providing
facilities for scale-up from bench-top to
engineering-scale.
• Include a wide variety of participants and partners.
Develop “best-in-class” technology.
• Deliver innovation via a collaborative project
portfolio that provides an accelerated pathway to
cost-effective CO2 capture technology.

5. Major CCS Demonstration Projects Project Locations & Cost Share
CCPI
ICCS Area 1
FutureGen 2.0
Southern Company
Kemper County IGCC Project
Transport Gasifier w/ Carbon Capture
~$2.01B – Total, $270M – -DOE
EOR – ~3.0 MM TPY 2014 start
NRG
W.A. Parish Generating Station
Post Combustion CO2 Capture
$775 M – Total
$167M – DOE
EOR – ~1.4 MM TPY 2016 start
Summit TX Clean Energy
Commercial Demo of Advanced
IGCC w/ Full Carbon Capture
~$1.7B – Total, $450M – DOE
EOR – ~2.2 MMTPY 2017 start
HECA
Commercial Demo of Advanced
IGCC w/ Full Carbon Capture
~$4B – Total, $408M – DOE
EOR – ~2.6 MM TPY 2019 start
Leucadia Energy
CO2 Capture from Methanol Plant
EOR in Eastern TX Oilfields
$436M - Total, $261M – DOE
EOR – ~4.5 MM TPY 2017 start
Air Products and Chemicals, Inc.
CO2 Capture from Steam Methane Reformers
EOR in Eastern TX Oilfields
$431M – Total, $284M – DOE
EOR – ~0.93 MM TPY 2012 start
FutureGen 2.0
Large-scale Testing of Oxy-Combustion w/ CO2 Capture and Sequestration in Saline Formation
Project: ~$1.78B – Total; ~$1.05B – DOE
SALINE – 1 MM TPY 2017 start
Archer Daniels Midland
CO2 Capture from Ethanol Plant
CO2 Stored in Saline Reservoir
$208M – Total, $141M – DOE
SALINE – ~0.9 MM TPY 2015 start

6. Regional Carbon Sequestration Partnerships Development Phase CO2 Injection Volumes
Injection volumes updated as of September 2014
Midwest Regional Carbon Sequestration Partnership
Michigan Basin Project
244,000 metric tons
Midwest Geological Sequestration Consortium
Illinois Basin Decatur Project
926,000 metric tons
Southeast Regional Carbon Sequestration Partnership
Citronelle Project
112,786 metric tons
Southeast Regional Carbon Sequestration Partnership
Cranfield Project
5,023,325 metric tons
Southwest Regional Carbon Sequestration Partnership
Farnsworth Unit – Ochiltree Project
113,663 metric tons
Plains CO2 Reduction Partnership
Bell Creek Field Project
997,392 metric tons
Big Sky Carbon Sequestration Partnership
Kevin Dome Project
Injection 2015

7. SECARB Integrated Anthropogenic Test
 Carbon capture from Plant Barry
(equivalent to 25MW of
electricity).
 12 mile CO2 pipeline constructed
by Denbury Resources.
 CO2 injection into ~9.400 ft. deep
saline formation (Paluxy) above
Citronelle Field
 Monitoring of CO2 storage during
injection and 3years post-injection.
7

8. Business Integration Questions
• Demonstrating integration of CO2 capture from a coal-fired
power plant with transport and injection into a deep saline
formation is pioneering for a CCS project.
• Key business integration questions:
• What business relationships must be established?
• How can CO2 transportation and injection impact the capture
unit?
• How can plant shutdown impact CO2 transportation and
injection?
• What types of communications and control systems are
needed?
8

9. CO2
absorption
Solvent
Regeneration
Compression
Solvent
Management
Gas Conditioning
Plant Barry Capture Unit: 25MW, 500 TPD
9

11. CO2 Capture Plant Performance
Items Results*
Total Operation Time hrs 11,200
Total Amount of Captured CO2 metric tons 211,860
Total Amount of Injected CO2 metric tons 100,600
CO2 Capture Rate metric tons per day > 500
CO2 Removal Efficiency % > 90
CO2 Stream Purity % 99.9+
Steam Consumption ton-steam/ton-CO2 0.98
• Gas In for CO2 Capture Plant: June, 2011
• Commissioning of CO2 Compressor: August, 2011
• Commissioning of CO2 Pipeline: March, 2012
• CO2 Injection: August, 2012
*As of 6/18/2014

12. Significant Technology Advancement
Item Main Results
Baseline mass and
heat balance
Verified that steam consumption was lower than expected under the design
condition (CO2 removal efficiency: 90%, CO2 capture rate: 500MTPD) (2011)
Emissions and
waste streams
monitoring
Successfully demonstrated amine emission reduction technologies under the
various SO3 concentration conditions – more than 90% reduction (2013)
Parametric test for
all process systems
Demonstrated several improved technologies for cost reduction (e.g. MHI
proprietary spray distributor) (2013)
Performance
optimization
Achieved 0.95 ton-steam/ton-CO2 by optimizing steam consumption. (2011)
Dynamic response
test for load
following
Carried out continuous control testing to optimize the operation condition with
self-developed dynamic simulator (2013)
Long term test to
validate equipment
reliability and life
Achieved 100,000 metric ton CO2 injection without operational issues (2013)
High impurities
loading test
Verified that amine emissions increased with higher SO3 loading (2011)
Verified removal of solvent impurities by reclaiming operation (2012, 2013)

13. Amine Emission Evaluation
More than 90%
Reduction
Fig. Relationship between SO3 conc. and solvent emission
High SO3 in the gas
Low SO3 in the gas
Fig. Absorber top
• Amine emissions increased significantly with a small amount of SO3 increase
• Proprietary amine emission reduction system decreased emissions down to less than
1/10 of the conventional system

14. Improved Technology for Cost Reduction
Fig. Trough Type Distributer
Fig. Spray Type Distributer
(MHI Proprietary)
• MHI developed a proprietary spray type distributor to reduce the weight
of tower internals
• Same performance of trough type with approximately 50% cost reduction

15. Technology Advancement Continues
•Built-in Reboiler
–Plan to evaluate a new built-in reboiler design to replace the shell and tube reboiler in solvent regeneration
•High Efficiency System (HES)
–Integration of waste heat recovery technology into the 25MW CCS demonstration plant
•CO2 Injection & Monitoring
–Additional 50,000 Mtons

16. Dedicated CO2 Pipeline: Plant Barry to Citronelle Field
 Avoiding
Gopher Tortoise
habitat on
pipeline route
Images Courtesy Southern Company
16

17. SECARB Anthropogenic Test SP101013
17
•Applicable regulatory standard: US Depart of Transportation, 49 CFR Part 195 —Transportation of Hazardous Liquids by Pipeline
•4-inch (10 cm) pipe diameter carbon steel pipe
•Normal operating pressure: 1,500 psig (10.3 MPa) maximum
•Buried average of 5 ft (1.5 m) with surface re-vegetation and erosion control
CO2 Pipeline and Measurement Design
Handling pipe for horizontal directional drill
17

18. CO2 Pipeline Overview
18
 Typical Pipeline/Injection
Operations
• 1,448 psi and 900F at the
transfer station
• Rate: 9.64MMcfd (~480
tonnes/day) at 1,314 psi
(wellhead) 630F.
 Typical CO2 Purity
Component %
N2 0.011
O2 0.010
CO2 99.979

19. Characterization of the Injection Site
Characterization Well D9-8 #2 at Citronelle Field - Drilled (Dec. 2010/Jan. 2011)
19

20. Geologic Storage Commercialization Value Chain
Applied Research
Core RD and Laboratory Projects
Storage Validation
Small/Large-Scale Injection Projects
Pre-Commercial Verification
Demonstration (ICCS, CCPI, FutureGen)
Commercial Deployment
Commercial Scale Testing
Regional Carbon
Sequestration Partnerships
Initiative
Advancing CCS through an Integrated Value Chain from Research to Commercial Deployment

21. Selecting a Good Storage Formation
21
• Proven four-way closure at
Citronelle Dome
• Injection site located within
Citronelle oilfield where existing
well logs are available
• Deep injection interval (Paluxy
Form. at 9,400 feet)
• Numerous confining units
• Base of USDWs ~1,400 feet
• Existing wells cemented through
primary confining unit
• No evidence of faulting or fracturing
(2D)

22. SECARB Anthropogenic Test SP101013
22
Extrapolated Continuity of Upper Paluxy Sandstones
At Citronelle Southeast Unit
Northwest - Southeast

23. SECARB Citronelle: MVA Sample Locations
23
• One (1) Injector (D-9-7 #2)
• Two (2) deep Observation
wells (D-9-8 #2 & D-9-9 #2)
• Two (2) in-zone Monitoring
wells (D-4-13 & D-4-14)
• One (1) PNC logging well (D-
9-11)
• Twelve (12) soil flux monitoring
stations

24. SECARB Anthropogenic Test SP101013
24
Whole Core Analyses & Confining Unit Characterization
CoreAnalysis
D 9-7 #2
D 9-8 #2
D 9-9#2
Spectral Gamma Ray
X
X
X
Routine Porosity, Permeability, Grain Density
X
X
X
Vertical and Orthogonal Permeability
X
X
X
Relative Permeability
X
X-ray Diffraction Mineralogy
X
X
X
Fluid Sensitivity – Permeability vs. Throughput
X
Thin-Section Petrography
X
X
X
Mercury Injection Capillary Pressure
X
Total Organic Carbon
X
X
Source Rock Analysis
X
X
Shale Rock Properties
X
X
Methane Adsorption Isotherm
X
X

25. Geology Summary for Simulation
25
Injecting into Paluxy @ 9,400 feet
>260 net feet of “clean” sand
Average porosity of 19%
(ranges from 14% to 24%)
Average permeability of 300 md
(ranges from 30md to 1,000
md)

26. SECARB Phase III Anthropogenic Test Risk Workshop
Trondheim, June 10-13 2013
Project Risk Assessment Matrix: DNV KEMA Approach
CONSEQUENCE
LIKELIHOOD
A: Remote B: Unlikely C: Possible D: Probable A: Certain
Health and safety (HS)
And
Environmental protection (E)
Cost Reputation
Schedule to
start-up of
operations
Very unlikely
(P<0.05) to
occur during
life of project
Unlikely to
occur during
life of project
50/50
chance of
occurring
during life of
project
Likely to
occur during
life of project
Very likely
(P>0.95) to
occur during
life of project
CONSEQUENCE SEVERITY
E: Persistent
Severe
HS: On site & off site
exposures/injuries.
E: Persistent severe damage,
Extensive remediation required.
Environment restored > 5 years.
More
than $10
million
National or
International
media attention.
Regulators shut
down operations.
More than 12
months
M M H H H
D: Severe
HS: On site injuries/exposures leading
to absence from work more than 5 days
or long term negative health effects.
E: Severe environmental damage.
Remediation measures required.
Environment restored < 5 years
$1 to
$10
million
Regional media
attention.
Regulatory or
legal action taken
6-12 months L M M H H
C: Moderate
HS: Lost time event/on site injury
leading to absence from work up to 5
days, or affecting daily life activities
more than five days. E: Damage
managed by Company response teams,
env. restored < 2 years.
$100 to
$1000 k
Local media
attention.
Regulatory or
legal action likely
3-6 months L L M M H
B: Minor
HS: Minor injury or health effect -
affecting work performance, such as
restricting work activities, or affecting
daily life activities for up to 5 days.
E: Damage, but no lasting effect.
$10 to
$100 k
Public awareness
may exist, but
there is no public
concern
1-3 months L L L M M
A: Slight
HS: Slight injury or health effect - not
affecting work performance or daily life
activities.
E: Damage contained within premises.
Less
than $10
k
On-site
communications
Less than 1
month
L L L L M
26

27. SECARB Citronelle: Top ranked risks
 Initially June 2011 the top ranked risks related to:
– Permitting – 30, 31
– Injectivity and containment – 8, 9, 10, 11
– Modelling and monitoring – 14, 32
– Reliable operations – 1, 23, 24, 38,
– Pipeline and wells – 3, 21, 34
 In January 2012, Class V permit had been granted and drilling of monitoring wells and
pipeline construction had been completed. Top ranked remaining risks related to:
– Authorization to inject – 31
– Containment – 8, 9, 10 (low likelihood, but high consequence)
– Reliability of operations – 23, 38
– Pipeline or casing leak – 21, 29
 In May 2013 project had been operating for 9 months. Top remaining risks related to
– Possible loss of containment – 8, 9, 10
– Reliability of operations – 23, 41
– Post-injection MVA / Authorization for closure – 52
27

28. Public Outreach and Education
 Public Outreach Plan using DOE Best Practices Model
 Active Community Engagement, Open House
Meetings and Tours
 Communicating Project Status
 Local, Regional, International Outreach
 Annual SECARB Stakeholders’ Briefing
 Dedicated Website
 Knowledge Sharing
Facebook Page: facebook.com/SECARB
Twitter Feeds: @SECARB1
28

29. FOSSIL.ENERGY.GOV
Pending carbon legislation
Oil @ $50 - $60 per barrel
High natural gas prices
High cost of CO2 capture
No carbon legislation pending
Oil @ $80-$100 per barrel
Low cost natural gas from shale
CO2 capture costs must be driven to business case economics
Then
Now
CCUS is a business-driven path to promote CO2 capture and storage

30.  Carbon pollution rule for new power plants, sets separate
CO2 emissions standards for coal and gas units and
provides incentives for plant developers to install carbon
capture and storage technology
 The proposal establishes four different emissions limits for
power plants depending on the type of unit:
– Coal-fired units – 1,100 lbs CO2/MWh over a 12-month
operating period;
– Coal-fired units that choose to average their emissions
over a seven-year period – 1,000 to 1,050 lbs CO2/MWh
over that 84-month operating period;
– Gas-fired turbines larger than 850 mmBtu/hr – 1,000 lbs
CO2/MWH; and
– Gas-fired turbines smaller than 850 mmBtu/hr – 1,100
lbts/MWh
30
EPA Unveils New Plant CO2 Rule (2013)

31. EPA Unveils Existing Plant CO2 Rule (2014)
31
U.S. EPA proposes four Building Blocks for
existing plants:
1. Reducing the carbon intensity at individual
EGUs through heat rate improvements.
2. Reducing CO2 emissions by substituting less
carbon-intensive generation (including NGCC
units under construction).
3. Reducing CO2 emissions by substituting low-or
zero-carbon generation.
4. Reducing CO2 emissions by use of demand-side
energy management.

32. August 6, 2012
JAF2012_081.PPT
Midwest/Ohio Valley Regional Attributes and CO2 Utilization Opportunities
32
LaBarge
Gas Plant
Val Verde
Gas Plants
Enid Fertilizer Plant
Jackson
Dome
McElmo Dome
Sheep Mountain
Bravo Dome
13
3
17
70
6
Dakota Coal
Gasification
Plant
Antrim Gas
Plant
2
1
4
Currently, 119 CO2-EOR projects provide 352,000 B/D.
New CO2 pipelines - - the 320 mile Green Pipeline and the 226 mile Encore Pipeline - - are expanding CO2-EOR to new oil fields and basins.
The single largest constraint to increased use of CO2-EOR is the lack of available, affordable CO2 supplies.
2
Source: Advanced Resources International, Inc., based on Oil and Gas Journal, 2012 and other sources.
Number of CO2-EOR Projects
Natural CO2 Source
Industrial CO2 Source
Existing CO2 Pipeline
CO2 Pipeline Under Development
119
Encore Pipeline
Denbury/Green Pipeline
U.S. CO2-EOR Activity
Lost Cabin Gas Plant
1

33. Next Generation CO2 Oil Recovery
33
0
5
10
15
20
25
Billion Tons of CO2
CO2 Requirements
Natural
Anthropogenic
20 Billion Tons of CO2 Yields 67 Billion Barrels of Additional Oil
0
10
20
30
40
50
60
70
80
CO2 Oil Recovery Billion BBL
CO2 Oil Recovery
Billion Barrels Oil
Context - Total Proven US Oil Reserves @ 2010 = 30.9 Billion BBL
BP Annual Statistical Review - 2011

34. Next Generation CO2-EOR
3

35. http://www.netl.doe.gov/energy- analyses/pubs/NextGen_CO2_EOR_06142011.pdf
Financial & Production Benefits from “Next Generation” CO2-EOR

36. CCUS 2nd Generation Technologies
(per DOE Testimony in Congress, 2 Feb 2014)
 DOE is supporting research to advance various
integrated power and capture technologies that may
achieve substantial cost reductions
 Second generation technologies and so-called
transformational technologies, will result in lower costs
for CCS implemented on coal power plants
 Second generation capture technologies must move
from the laboratory to pilot testing (<50MW) and actual
demonstration (>100MW) by the mid-2020s
3

37. CCUS 2nd Generation Technologies
(Request for Information, 2 Sep 2014)
 DOE RFI “Testing Advanced Post-Combustion Carbon
Dioxide Capture Technologies at a Large Pilot Scale”
 DOE anticipates the need for large pilot-scale post-combustion
carbon capture projects that must be
completed by 2020
 DOE goal of having technologies ready for
commercial-scale demonstration by 2020, i.e.,
sufficiently developed and scaled-up by 2020 to enable
inclusion in the design of a first-of-kind demonstration
plant.
3

38. 2nd Generation CCUS Technologies
(CO2 Offshore Utilization & Storage Options)
 2011: “Continued Evaluation of Potential for Geologic
Storage of Carbon Dioxide in the Southeastern United
States” SSEB with Offshore evaluation by UT BEG
 2011: Formation of the OCS Governors Coalition, currently
including North Carolina (chair), Alaska, Texas, Louisiana,
Mississippi, Alabama, South Carolina and Virginia.
 2012: “Preliminary Evaluation of Offshore Transport,
Utilization and Geologic Storage of Carbon Dioxide: North
Carolina and South Carolina Waters” SSEB & University of
North Carolina - Charlotte
3

39. TX: federal offshore (BEG)
LA & MS: state and federal offshore (BEG)
AL & FL Panhandle: state and federal offshore (GSA)
Legal & Regulatory Analysis (IOGCC with team participation) Outreach & Education (SSEB & IOGCC) Project Management (SSEB)

40. Southeast Regional Carbon Sequestration
Partnership
QUESTIONS?
CCS Seminar
UKCCSRC
University of Edinburgh
19 September 2014
Gerald R. Hill, Ph.D.
Senior Technical Advisor
Southern States Energy Board