The Global CCS Institute presented a workshop at the American Institute of Chemical Engineers (AIChE) ‘Carbon Management Technology Conference’ in Alexandria, Virginia on 20 October 2013.

1. CCS/CCUS Overview:
What It Is and What Are Its Implications?
AIChE Carbon Management Conference, Alexandria, VA
20 October 2013

2. Agenda
1:00
Welcome and Introductions
1:15
The Role of CCS/CCUS
1:45
Capturing CO2 From Power Generation and Industrial
Processes
2:15
Transport/Storage/Utilization of CO2
3:00
Legal/Regulatory Framework
3:30
Panel Discussion: Proactively Addressing the
Management of CO2
4:00
Summary and Wrap-up
4:30
Networking Reception

3. Introducing the Global CCS Institute
The Global CCS Institute accelerates carbon capture
and storage, a vital technology to tackle climate
change and provide energy security.
We advocate for CCS as a crucial component in a portfolio of
technologies required to reduce greenhouse gas emissions.
 We drive the adoption of CCS as quickly and cost effectively
as possible by sharing expertise, building capacity and
providing advice and support to overcome challenges.
 Our diverse international Membership comprises
governments, global corporations, small companies,
research bodies and non-government organisations
committed to CCS as an integral part of a low–carbon future.
3

4. Globally
connected
membership
INSTITUTE MEMBERSHIP NUMBERS AND LOCATIONS
TOTAL 378
80
136
82
3
5
74

5. The Global CCS Institute – what we do
Expert
support
to
Members
/
Projects
Comprehensive
resources
Networking
capability
Best
pracHce
guidelines
and
toolkits

6. The Global Status of CCS: 2013
Key Institute publication
 2013 edition: released 10 October
 Comprehensive coverage on the
state of CCS projects and
technologies
 Project progress outlined since 2010
 Includes recommendations for
moving forward
6

7. CCS/CCUS
Overview:
What
Is
It
&
What
Are
Its
ImplicaHons?
CCS/CCUS
OVERVIEW:
The
Role
of
CCS/CCUS
Prepared By:
Steven M. Carpenter, Vice, President
ADVANCED RESOURCES INTERNATIONAL, INC.
Arlington, VA
20 October 2013
7

8. Presentation Topics
30,000 ft view – why are we here?
CCS vs. CCUS
Major Project portfolio
Standardization is key
8

9. Background
–
Why
are
we
here?
9

10. Energy is Good: 25/90% Population
NORTH KOREA
• 20% access to electricity
• Population is 3” shorter & 7 lbs. lighter
• Infant Mortality Rate in 12 x higher
• 156th in GDP/Capita
SOUTH KOREA
• 90% access to electricity
• Population is 3” taller & 7 lbs. heavier
• Infant Mortality Rate 12 x lower
• 32nd in GDP/capita
10

11. What is CCS?
11

12. What is CCS?
12

13. What is CCS?
13

14. What is CCS?
14

15. Setting the expectations…
•
•
•
•
15
December
17,
1903
20
feet
in
alFtude
120
feet
in
distance
12
seconds
in
duraFon

16. David Black’s Flyover
16

17. In just 17 short years…
• 2003:
DOE
Carbon
SequestraFon
Partnerships
• 2010:
White
House
Interagency
JTF
on
CCS
• 2016:
5-­‐10
full
scale
demonstraFons
• 2020:
Widespread
commercial
deployment
17

18. In 17 years we go from…
18

19. …to this…
19

20. CCS
vs.
CCUS
–
What
is
CO2-­‐EOR
&
why
is
it
important?
20

21. What is CCS?
21

22. What is CCS?
22

23. Integrating CO2-EOR and CO2 Storage Could
Increase Storage Potential
CO2 Source
Oil to
Market
Production Well
CO2
Injection
CO2
Recycled
Swept Area
Current Water
Oil Contact
Original
Water
Oil Contact
Oil Bank
Unswept Area
TZ/ROZ
Saline Reservoir
Stage #1
Stage #2
Stage #3

24. U.S.
CO2-­‐EOR
AcFvity
–
Oil
Fields
&
CO2
Sources
120
Dakota
Coal
GasificaFon
Plant
Natural
CO2
Source
Industrial
CO2
Source
Antrim
Gas
Plant
1
LaBarge
Gas
Plant
6
Encore
Pipeline
2
McElmo
Dome
Sheep
Mountain
Bravo
Dome
1
Enid
FerFlizer
Plant
3
5
2
Jackson
Dome
17
Denbury/Green
Pipeline
Source: Advanced Resources International, Inc., based on Oil and Gas Journal, 2012 and other sources.
24
ExisHng
CO2
Pipeline
CO2
Pipeline
Under
Development
 120 CO2-EOR projects
provide 352,000 bbl/day
13
Lost
Cabin
Gas
Plant
70
Val
Verde
Gas
Plants
Number
of
CO2-­‐EOR
Projects
 New CO2 pipelines are
expanding CO2-EOR to new
oil fields and basins.
 320 mile Green
Pipeline
 226 mile Encore
Pipeline

25. Significant Volumes of CO2 Are Already Being
Injected for EOR in the U.S.
Location of
EOR / Storage
CO2 Source Type and Location
CO2 Supply (MMcfd)
Geologic
Anthropogenic
1,600
190
-
300
930
-
Texas, New Mexico,
Oklahoma, Utah
Geologic (Colorado, New Mexico)
Gas Processing, Fertilizer Plant (Texas)
Colorado, Wyoming
Gas Processing (Wyoming)
Mississippi
Geologic (Mississippi)
Michigan
Gas Processing (Michigan)
-
10
Oklahoma
Fertilizer Plant (Oklahoma)
-
35
Saskatchewan
Coal Gasification (North Dakota)
-
150
2,530
685
49
13
TOTAL (MMcfd)
TOTAL (MMt per year)
* Source: Advanced Resources International, 2012
**MMcfd of CO2 can be converted to million metric tons per year by first multiplying by 365 (days per year) and then dividing by
18.9 * 103 (Mcf per metric ton)
25

26. Oil
Recovery
&
CO2
Storage
From
"Next
GeneraFon"
CO2-­‐EOR
Technology*
Oil Recovery***
(Billion Barrels)
Reservoir Setting
CO2 Demand/Storage***
(Billion Metric Tons)
Technical
Economic**
Technical
Economic**
L-48 Onshore
104
60
32
17
L-48 Offshore/Alaska
15
7
6
3
Near-Miscible CO2-EOR
1
*
1
*
ROZ (below fields)****
16
13
7
5
Sub-Total
136
80
46
25
Additional From
ROZ “Fairways”
40
20
16
8
*The values for economically recoverable oil and economic CO2 demand (storage) represent an update to the numbers in the NETL/ARI report “Improving Domestic
Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR) (June 1, 2011).
**At $85 per barrel oil price and $40 per metric ton CO2 market price with ROR of 20% (before tax).
***Includes 2.6 billion barrels already being produced or being developed with miscible CO2-EOR and 2,300 million metric tons of CO2 from natural sources and gas
processing plants.
**** ROZ resources below existing oilfields in three basins; economics of ROZ resources are preliminary.
26
26

27. Number of 1 GW Size Coal-Fired Power Plants*
Demand
for
CO2:
Number
of
1
GW
Size
Coal-­‐Fired
Power
Plants
Technical Demand/
Storage Capacity
300
Total CO2
Anthropogenic CO2
Economic Demand/
Storage Capacity**
Total CO2
Anthropogenic CO2
Technical
L-48 Onshore
133
121
100
0
90
31
14
Near-Miscible CO2EOR
200
170
L-48 Offshore/Alaska
228
Economic*
5
1
ROZ**
34
28
Sub-Total
240
*Assuming 7 MMmt/yr of CO2 emissions, 90% capture and 30 years of operations per 1 GW of generating capacity.
**At an oil price of $85/B, a CO2 market price of $40/mt and a 20% ROR, before.
Source: Advanced Resources Int’l (2011).
27
Reservoir
Setting
Number of
1GW Size Coal-Fired
Power Plants***
240
133
Additional From
ROZ “Fairways”
86
43
*At $85 per barrel oil price and $40 per metric ton CO2 market price with ROR
of 20% (before tax).
** ROZ resources below existing oilfields in three basins; economics of ROZ
resources are preliminary.
***Assuming 7 MMmt/yr of CO2 emissions, 90% capture and 30 years of
operation per 1 GW of generating capacity; the U.S. currently has
approximately 309 GW of coal-fired power plant capacity.

28. Linking
CO2
Supplies
with
CO2-­‐EOR
Demand
0
The
primary
EOR
markets
for
excess
CO2
supplies
from
the
Ohio
Valley,
South
AtlanFc
and
Mid-­‐
ConFnent
is
East/West
Texas
and
Oklahoma.
0.2
0.6
2.0
6.3
3.7
4.2
3.7
0.3
0.2
8 Bcfd
7.4
0.2
Captured CO2 Supplies and CO2 Demand
Region
New England
Middle Atlantic
South Atlantic
East North Central
West North Central
East South Central
West South Central
Mountain
Pacific
Total
ROZ "Fairways"
Captured CO2
Supplies*
(BMt)
CO2
Excess CO2
Demand
Supply
(BMt)
(BMt)
0.2
2.3
7.4
4.2
6.3
3.6
4.3
3.7
0.3
0.2
0.2
0.6
2.0
0.2
14.2
3.7
4.2
32.2
25.3
20.8
* Capture from 200 GW of coal-fired power plants, 90% capture rate.
28
3.6
Net CO2
Demand
(BMt)
8.0
14.2
-­‐
0.2
2.1
7.2
3.6
4.3
3.3
8.0
0.2
2.3
4.2
4.3
cfd
19 B
cfd
13 B
Jackson Dome
9.9
Pacific
3.8
0.3
13.7
8.0
JAF2012_035.XLS
4.2
CO2 Demand by EOR (Bmt)
Captured CO2 Emissions (Bmt)
Sources: EIA Annual Energy Outlook 2011 for CO2 emissions; NETL/Advanced
Resources Int’l (2011) CO2 demand.

29. CO2-EOR Global Potential
Region Name
Asia Pacific
Central and South America
Europe
Former Soviet Union
Middle East and North Africa
North America/Other
North America/United States
South Asia
S. Africa/Antarctica
Total
29
Basin
Count
8
7
2
6
11
3
14
1
2
54
EIA
assessment
of
54
large
world
oil
basins
for
CO2-­‐
based
Enhanced
Oil
Recovery
•
High
level,
1st
order
assessment
of
CO2-­‐EOR
and
associated
storage
potenFal,
using
U.S.
experience
as
analog.
•
Tested
basin-­‐level
esFmates
with
detailed
modeling
of
47
large
oil
fields
in
6
basins.

30. CO2-EOR Global Potential
30

31. CCUS Dependency & Challenges
• Growth
in
producFon
from
CO2-­‐EOR
is
limited
by
the
availability
of
reliable,
affordable
CO2.
• If
increased
volumes
of
CO2
do
not
result
from
CCUS,
then
these
benefits
from
CO2-­‐EOR
will
not
be
realized.
• Therefore,
not
only
does
CCUS
need
CO2-­‐EOR
to
ensure
viability
of
CCUS,
but
CO2-­‐EOR
needs
CCUS
to
ensure
adequate
CO2
to
facilitate
CO2-­‐EOR
growth.
• This
will
become
even
more
apparent
as
potenFal
even
more
new
targets
for
CO2-­‐EOR
become
recognized
&
internaFonal
desire
for
CO2-­‐EOR
grows.
31

32. Major
CCS
Project
Poriolio
32

33. Major CCS Demonstration Projects
CCPI
FutureGen 2.0
Large-­‐scale
TesHng
of
Oxy-­‐CombusHon
DOE
Share:
Plant
-­‐
$1.04B
SALINE
–
1M
TPY
2017
start
ICCS
Area
1
FutureGen
2.0
Archer Daniels Midland
CO2
Capture
from
Ethanol
Plant
DOE
Share:
$141M
SALINE
–
~0.9M
TPY
2014
start
Summit TX Clean Energy
Commercial
Demo
of
Advanced
IGCC
w/
Full
Carbon
Capture
DOE
Share:
$450M
EOR
–
~2.2
TPY
2017
start
Southern Company
Kemper County IGCC Project
Novel
Transport
Gasifier
w/Carbon
Capture
DOE
Share:
$270M
EOR
–
~3.0
M
TPY
2014
start
HECA
Commercial
Demo
of
Advanced
IGCC
w/
Full
Carbon
Capture
DOE
Share:
$408M
EOR
–
~2.6M
TPY
2019
start
NRG
W.A. Parish Generating Station
Post
CombusHon
CO2
Capture
DOE
Share:
$167M
EOR
–
~1.4M
TPY
2016
start
33
Air Products and Chemicals, Inc.
CO2
Capture
from
Steam
Methane
Reformers
DOE
Share:
$284M
EOR
–
~0.93M
TPY
2012
start
Leucadia Energy
CO2
Capture
from
Methanol
Plant
DOE
Share:
$261M
EOR
–
~4.5
M
TPY
2017
start

34. RCSP Phase III: Development Projects
Core
Sampling
Taken
Seismic
Survey
5
Completed
InjecFon
Started
June
2013
InjecFon
began
Nov
2011
1
4
InjecFon
started
in
depleted
reef
February
2013
3
Partnership
Geologic Province
Target Injection Volume
(tonnes)
1
Big Sky
Nugget Sandstone
1,000,000
2
MGSC
3
2
9
MRCSP
8
6
InjecFon
Started
April
2009
InjecFon
Ongoing
2013
InjecFon
Scheduled
 Large-­‐volume
tests
 Four
Partnerships
currently
injec9ng
CO2
 Remaining
injec9ons
scheduled
2013-­‐2015
7
InjecFon
began
August
2012
4
5
PCOR
6
SECARB
InjecFon
Scheduled
2013-­‐2015
7
8
SWP
9
WESTCARB
34
Illinois BasinMt. Simon Sandstone
Michigan BasinNiagaran Reef
Powder River BasinBell Creek Field
Horn River BasinCarbonates
Gulf Coast – Cranfield
Field- Tuscaloosa
Formation
Gulf Coast – Paluxy
Formation
Regional CCUS
Opportunity
1,000,000
1,000,000
1,500,000
2,000,000
3,400,000
250,000
1,000,000
Regional Characterization

35. Global Portfolio
35

36. Global Portfolio - LSIP
GCCSI identified 65 Large Scale Integrated Projects
3 new LSIPs in Brazil, China, and Saudi Arabia
13 LSIPs removed/cancelled since 2012
4 LSIPs have commenced operation since 2012, for a total of
12 LSI-CCS projects in operation
Reduction in # LSIPs reduces CO2 captured/stored from 148
million tonnes per annum (Mtpa) to 122
36

37. Importance of CCUS (CO2-EOR)
SecFon
7.2:
CO2–EOR
DOMINATES
GEOLOGIC
STORAGE
“It
is
es9mated
that
during
the
past
40
years
nearly
1
Gt
of
CO2
has
been
injected
into
geological
reservoirs
as
part
of
CO2–EOR
ac9vi9es.”
•
Accounts for 78% of DOE Demonstration Projects (7
of 9)
•
Accounts for 52% of LSIPs at various stages of the
asset life cycle (34 of 65)


37
63% of operating phase projects (5 of 8)
75% of execution phase projects (3 of 4)
Projects underway or planned in North America, South
America, Europe, Asia, and Australia

38. StandardizaFon
38

39. EPA’s Regulatory “Train Wreck”
Source:
Edison
Electric
InsFtute;
Dick
Winschel,
CONSOL
Energy
39

40. CCS Regulatory “Train Wreck”
40

41. TC-265 Working Groups
TC-­‐265
Twined
Secretariat
Capture
41
Transport
Storage
QuanFficaFon
&
VerificaFon
Crossculng
CO2-­‐EOR

42. Thank you
Office Locations
Washington, DC
4501 Fairfax Drive, Suite 910
Arlington, VA 22203
Phone: (703) 528-8420
Fax: (703) 528-0439
Houston, TX
11931 Wickchester Ln., Suite 200
Houston, TX 77043
Phone: (281) 558-9200
Fax: (281) 558-9202
Knoxville, TN
603 W. Main Street, Suite 906
Knoxville, TN 37902
Phone: (865) 541-4690
Fax: (865) 541-4688
Cincinnati, OH
1282 Secretariat Court
Batavia, OH 45103
Phone: (513) 460-0360
Email: scarpenter@adv-res.com
http://adv-res.com/
42

43. Capturing CO2 From Power Generation
and Industrial Processes
Kevin C O’Brien, PhD
Principal Manager Carbon Capture – the Americas

44. Defining Carbon Capture
The Cost Driving Step in CCS / CCUS

45. Post Combustion Capture
Challenges

Most technologies need significant scaling to be relevant to power
generation

Loss of power around 30%





Needs cleaning of flue gases (SOx and NOx)
Integration may reduce flexibility of power plant
Increase in water around 35%
Significant space requirements could be a challenge at well established
sites
Amine emissions

46. Pre-Combustion Capture
Challenges:

Energy penalty still significant at around 20%

Commercial scale hydrogen turbine still to be demonstrated

Additional purification may be required in the event of venting

Gasification plants are unfamiliar to the power sector

47. Oxy-Combustion (Oxyfuel)
Challenges:

Requires an integrated plant

Development will require a whole of plant approach

Air separation unit requires around 25% of electricity produced

Start up using air may require additional gas treating equipment

Increased water consumption

48. Large Scale Capture
LSIP = Large Scale Integrated Project
800,000 tpa for coal-based power gen
400,000 tpa for emission-intensive industrial facilities (including natural gas-based power
generation)

49. Large scale integrated CCS projects (LSIPs)

50. Wide variety of capture options being planned
Projects by capture type and industry
Power
generation
Industrial
applications
0
5
10
Number of projects
Pre-combustion (gasification)
Post-combustion
Industrial separation
15
20
25
30
35
40
45
Pre-combustion (natural gas processing)
Oxy-fuel combustion
Various/Not decided

51. Significant amounts of CO2 are already being captured and
stored
CO2 captured by industry and project development stage
Power generation
Natural gas
processing
Other industries
0
10
Mass of CO2 (Mtpa)
Identify
Evaluate
20
Define
30
Execute
40
Operate
50
60

52. Regional variations exist in preferred capture technology
Projects by location and capture type
United States
Europe
China
Canada
Australia
Middle East
Other Asia
South America
Africa
0
5
10
15
20
Number of projects
Pre-combustion (gasification)
Pre-combustion (natural gas processing)
Post-combustion
Oxy-fuel combustion
Industrial separation
Various/Not decided
25

53. Challenges for large-scale carbon capture
• Demonstrating capture at larger scale in more industries
• Reducing costs, including through the development of new
technologies
• More effective knowledge sharing
• Integration of capture into large-scale power and industrial
applications
• Flexible operation of power stations with CCS

54. Capture R&D
Provides Promise of Driving Down
Capture Costs

55. Solvent Based Process
• Absorption based process
• Dissolve CO2 into solvent, i.e. aqueous amine
• Solvent regeneration by heating

56. Sorbent Based Process
• Physi or Chemi sorption based process
• Packed or Fluidized Beds
• Lower pressure or increase temperature to regenerate

57. Membrane Based Process
• Typically thin dense layer on porous substrate
• Permeation of CO2 through dense layer due to solution / diffusion
through membrane
• N2 and other components rejected (retentate) and emitted up the
stack

58. Relative Maturity of Capture Technologies
DOE/NETL’s
Exis-ng
Plants
R&D
Program
–Carbon
Dioxide,
Water,
&
Mercury,
June
2010

59. Final observations
• Carbon capture is an established commercial
process in natural gas and chemical production.
• Carbon capture is being demonstrated in power
generation.
• Primary challenges for capture are related to
process economics – parasitic power and capital
costs
• There are many options for capture approaches and
processes – there is no “holy grail”
• Continued R&D in capture is vital to reduce overall
costs of CCS / CCUS

61. Southeast Regional Carbon Sequestration Partnership
CCS/CCUS Demonstration Projects
Presented to:
The Global CCS Institute’s
CCS/CCUS Overview Workshop
Alexandria, VA
October 20, 2013
Presented by:
Gerald R. Hill, Ph.D.
Senior Technical Advisor
Southern States Energy Board

62. 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.
62

63. Presentation Outline

SECARB Early Test, Cranfield,
Mississippi
– Project Overview
– Lessons Learned: Large Scale
Injection at CO2-EOR Site
– Commercial Significance of CCUS

SECARB Anthropogenic Test,
Citronelle, Alabama
– Project Overview
– Lessons Learned: Capture,
Transportation & Injection
Integration
– Innovative monitoring techniques
63

64. SECARB’s Early Test
Cranfield, Mississippi
64

65. SECARB Early Test
Monitoring Large Volume Injection at Cranfield
Mississippi River
Natchez
Mississippi
3,000 m depth
Gas cap, oil ring, downdip water leg
Shut in since 1965
Strong water drive
Returned to near initial pressure
Illustration by Tip Meckel
65

66. Cranfield Early Test Monitoring: Detailed Area of Study
66

67. Cumulative
CO2 Injected
9,000,000
July,
2013
8,000,000
7,000,000
CO2
(Metric
Tons)
6,000,000
5,000,000
4,000,000
8,073,395
Cumulative
Total
Cumulative
Volume
Injected
West
Cumulative
Volume
Injected
East
4,146,143
3,927,251
3,000,000
2,000,000
1,000,000
Jul-­‐08
Sep-­‐08
Nov-­‐08
Jan-­‐09
Mar-­‐09
May-­‐09
Jul-­‐09
Sep-­‐09
Nov-­‐09
Jan-­‐10
Mar-­‐10
May-­‐10
Jul-­‐10
Sep-­‐10
Nov-­‐10
Jan-­‐11
Mar-­‐11
May-­‐11
Jul-­‐11
Sep-­‐11
Nov-­‐11
Jan-­‐12
Mar-­‐12
May-­‐12
Jul-­‐12
Sep-­‐12
Nov-­‐12
Jan-­‐13
Mar-­‐13
May-­‐13
Jul-­‐13
0
Time
SECARB Early Test: Cumulative CO2 Injected, July 2013
6

68. 6
Time
SECARB Early Test: Cranfield Net CO2 Stored, July 2013
Jul-­‐13
4,500,000
May-­‐13
Mar-­‐13
Jan-­‐13
Nov-­‐12
Sep-­‐12
Jul-­‐12
May-­‐12
Mar-­‐12
Jan-­‐12
Nov-­‐11
Sep-­‐11
Jul-­‐11
May-­‐11
Mar-­‐11
Jan-­‐11
Nov-­‐10
Sep-­‐10
Jul-­‐10
May-­‐10
Mar-­‐10
Jan-­‐10
Nov-­‐09
Sep-­‐09
Jul-­‐09
May-­‐09
Mar-­‐09
Jan-­‐09
Nov-­‐08
Sep-­‐08
Jul-­‐08
CO2
(Metric
Tons)
5,000,000
Cranfield
Net
CO2 Stored
July,
2013
4,377,834
4,000,000
CO2
Stored
3,500,000
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
0

69. Midwest/Ohio Valley Regional Attributes and CO2 Utilization Opportunities
U.S. CO2-EOR Activity
119
Dakota Coal
Gasification
Plant
Natural
CO2
Source
Industrial
CO2
Source
Antrim Gas
Plant
1
LaBarge
Gas Plant
Encore Pipeline
6
1
Enid
FerFlizer
Plant
4
McElmo Dome
Sheep Mountain
Bravo Dome
3
70
Val Verde
Gas Plants
2
Jackson
Dome
17
Denbury/Green Pipeline
Source: Advanced Resources International, Inc., based on Oil and Gas Journal, 2012 and other sources.
69
JAF2012_081.PPT
August 6, 2012
ExisFng
CO2
Pipeline
CO2
Pipeline
Under
Development
 Currently, 119 CO2-EOR
projects provide 352,000 B/D.
13
Lost
Cabin
Gas
Plant
2
Number
of
CO2-­‐EOR
Projects
 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.

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

71. x
x
NETL Next Generation CO2 Oil Recovery
CO2 Oil Recovery
80
CO2 Requirements
CO2 Oil Recovery Billion BBL
25
20
Billion Tons of CO2
70
15
10
5
60
50
40
30
20
10
0
0
Natural
Anthropogenic
Billion Barrels Oil
Context - Total Proven US Oil Reserves @ 2010 = 30.9 Billion BBL
BP Annual Statistical Review - 2011
71

72. SECARB’s Anthropogenic Test
Citronelle, Alabama
72

73. SECARB Phase III Anthropogenic Test





Carbon capture from Plant Barry
equivalent to 25MW.
12 mile CO2 pipeline constructed
by Denbury Resources.
CO2 injection into ~9.400 ft. deep
saline formation (Paluxy)
Over 90,000 metric tons
injected (October 2013)
Monitoring CO2 during injection
and 3 years post-injection.
73

74. CO2
absorption
Solvent
Management
Solvent
Regeneration
Gas Conditioning
Plant Barry Capture Unit: 25MW, 500 TPD
Compression
74

75. Start with a Good Storage Site
• 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)
75

76. SECARB Citronelle: MVA Sample Locations
• 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
76

77. The image cannot be displayed. Your
computer may not have enough memory to
open the image, or the image may have
been corrupted. Restart your computer, and
then open the file again. If the red x still
77

78. The image cannot be displayed. Your
computer may not have enough memory to
open the image, or the image may have
been corrupted. Restart your computer, and
then open the file again. If the red x still
78

79. The image cannot be displayed. Your
computer may not have enough memory to
open the image, or the image may have
been corrupted. Restart your computer, and
then open the file again. If the red x still
79

80. SECARB Citronelle: MVA & Closure




Shallow MVA
– Groundwater sampling (USDW Monitoring)
– Soil Flux
– PFT Surveys
Deep MVA
– Reservoir Fluid sampling
– Crosswell Seismic
– Mechanical Integrity Test (MIT)
– CO2 Volume, Pressure, and Composition analysis
– Injection, Temperature, and Spinner logs
– Pulse Neutron Capture logs
– Vertical Seismic Profile
MVA Experimental tools
Closure – plug & abandon wells
Baseline
1 year
APR 2011 to AUG 2012
Injection
2 years
Post
3 years
SEPT 2012 to SEPT 2014
OCT 2014 to SEPT 2017
80

81. Future Plans
Citronelle UIC Permit Requirement:
“… the permittee shall demonstrate to the Department,
using monitoring and modeling data and other
information that the CO2 is safely confined within the
injection zone and that USDWs are not endangered by
the CO2 plume.”
Citronelle Monitoring Question:
What active or passive tests can we perform during site
closure that will help demonstrate to regulators that the
CO2 is trapped (or the plume is slowing) and no longer
an endangerment to USDWs?
81

82. CO2
Storage
in
UnconvenHonal
Gas
FormaHons
with
Enhanced
Gas
Recovery
PotenHal
Nino
Ripepi,
Assistant
Professor,
Department
of
Mining
&
Minerals
Engineering
Virginia
Center
for
Coal
and
Energy
Research
Virginia
Tech
CMTC CCS Session
October 20, 2013, Alexandria, VA

83. CO2
Storage
and
Enhanced
Coalbed
Methane
Recovery
(ECBM)
• Shallow
reservoir
with
low
P
&
T
can
result
in
lower
compression
costs
• Gas
is
stored
in
coal
securely
by
adsorpFon
rather
than
by
free
storage
or
soluFon
• Unmineable
Coal
Seams:
200
Billion
Tons
of
Capacity
in
the
U.S.
–
25
years
of
current
GHG
emissions
(DOE)
• ECBM
potenFal
~
150
Tcf
(Reeves,
2002)
• Central
App:
>
than
6,000
CBM
wells

84. CBM
and
ECBM
Mechanisms
Gas
Content
Coalbed
Methane
ProducFon
(CBM)
Enhanced
Coalbed
Methane
ProducFon
(ECBM)
VL
VL/2
Dewatering
Under
saturated
PL
(i) Dewatering:
pressure
,
effecFve
stress
,
fracture
apertures

permeability

(ii) CH4
releasematrix
shrinkage
and
zero
volume
change
condiFon,
fracture
apertures

,
permeability

• Net
Permeability:
CompeFng
effects
(i)-­‐(ii)
Pressure
CO2
CH4
(i) CO2
greater
affinity
to
coal
than
CH4
(ii) Depending
on
coal
rank
coal
matrix
can
adsorb
twice
to
as
hish
as
ten
Fmes
more
CO2
as
CH4
(iii) When
CO2
is
adsorbed
matrix
swells;
under
zero
volume
change
condiFon,
fracture
apertures

,
permeability


85. Virginia
Tech
InjecFon
Tests
(Funded
by
NETL/DOE,
Managed
or
in
Partnership
with
SECARB/SSEB)
• Performed
Pilot
CO2
InjecFon
Field
Tests
in
Virginia
(1,000
tons)
and,
under
the
direcFon
of
the
GSA,
in
Alabama
(300
tons)
(Phase
II,
2005–2010)
• In
Progress,
a
Small-­‐Scale
InjecFon
Test
in
Central
Appalachia
(20,000
tons)
into
UnconvenHonal
Storage
Reservoirs
with
Emphasis
on
Enhanced
Coalbed
Methane
Recovery
(2011–2015)

86. Russell
County
-­‐
Coal
Seams
Stage 4
Monitoring
Well
RU-84
BD114
Injection
Well
9.6 m
(3 ft)
Monitoring
Well
Greasy Creek 1
Seaboard 2
Lower Seabord 1&2
Lower Seaboard 3
Upper Horsepen 2&3
Stage 3
9.8 m
(3 ft)
Middle Horsepen 1
Middle Horsepen 2
Pocahontas 11
Pocahontas 10
Lower Horsepen 1
Lower Horsepen 2
Stage 2
4th Hydraulic
Fracture Zone
9.3 m
(2.8 ft)
3rd Hydraulic
Fracture Zone
Stage 1
2nd Hydraulic
Fracture Zone
1st Hydraulic
Fracture Zone
Pocahontas 9
Pocahontas 8-1
Pocahontas 8-2
Pocahontas 7-1A
Pocahontas 7-1B
Pocahontas 7-2
Pocahontas 7-3
7.6 m
!(2.3 ft)
Pocahontas 6
Pocahontas 5
Pocahontas 4-1
Pocahontas 4-2
Pocahontas 3-1
Pocahontas 3-4

87. CO2
InjecHon

88. 09
8/
/0
02
09
5/
/0
02
09
2/
/0
02
09
09
0/
/3
01
7/
/2
01
09
4/
/2
10
10
10
10
10
10
10
10
10
11
11
Injection Well (psia)
CO2 Process Temperature (F)
CO2 Injection Rate (tons/day)
900
90
800
80
700
70
600
60
500
50
400
40
300
30
200
20
100
10
0
0
CO2 Injection Rate (tons/day)
1000
01
09
1/
/2
01
09
09
8/
/1
01
09
5/
/1
01
2/
/1
01
09
9/
/0
01
Injection Pressure (psia)
Temperature (Degrees F)
CO2
InjecFon
100

90. Tracer
Injec-on
January
21,
2009
-­‐
500
ml
of
the
PTMCH
tracer
Miskovic,
2011

91. 0
03/22/11
02/19/11
01/20/11
140
100
70
80
60
50
60
40
40
30
20
20
10
0
Gas
ComposiHon
(%)
Methane
12/20/10
11/20/10
10/20/10
09/20/10
08/20/10
Carbon
Dioxide
07/21/10
06/20/10
05/21/10
04/20/10
03/21/10
02/18/10
BD-­‐114
Flowback
01/19/10
12/19/09
11/19/09
10/19/09
09/19/09
08/19/09
07/20/09
06/19/09
05/20/09
Gas
ProducHon
(Mcf/day)
Russell
County
Flowback
Nitrogen
100
90
120
80

92. CO2
InjecFon
Decline-­‐Curve
Analysis
Phase
II
InjecFon
Well
RU-­‐84
(BD-­‐114)
Gas Production,
Mcf/month
Post CO2 Injection EUR = 534 MMcf
Pre CO2 Injection EUR = 319 MMcf
Shut-in Period with CO2 Injection
mid November ‘08 – mid May ‘09

93. Conclusions
from
Russell
County
InjecHon
Test
• 1,007
tons
of
CO2
injected
into
19
coal
seams
in
2009
• InjecFon
rate
higher
than
anFcipated
at
an
average
of
over
40
tons
per
day,
but
decrease
at
the
end
to
an
injecFon
rate
of
<20
tons
per
day
• ECBM
measured
in
2
wells
(Unsustainable
due
to
small
CO2
volume)
• Tracer
detecFon
at
off-­‐set
wells,
but
no
measured
CO2
breakthrough
• Flowback
– ProducFon
returned
to
beser
than
pre-­‐injecFon
rates
– Flowback
showed
N2,
CH4
then
CO2
desorpFon

94. Current
Small-­‐Scale
InjecHon
Test
in
Central
Appalachia
 Objectives:
 Inject 20,000 metric tons of CO2 into 3 CBM
wells over a one-year period in Buchanan
County, VA
 Perform a small 300-1,000 ton Huff and Puff
test in a horizontal shale gas well in Morgan
County, TN
 Duration:
 4 years, October 1, 2011–September 30, 2015
 Funding:
 Total Project Value: $14,374,090
 DOE/Non-DOE: $11,499,265 / $2,874,825

95. Field demonstration in Buchanan County, VA
Scheduled October 2013

96. CO2
Plume
by
Layer

97. MVA program for Buchanan County test
Repeated from Russell County test:
•
•
•
Atmospheric monitoring with IRGAs to measure CO2 concentration
Surface methods including soil CO2 flux, surface water sampling and shallow
tracer detection
Offset well testing for gas composition (CO2 concentration, tracers, ECBM)
New components:
• Multiple tracer injection
• 3 monitoring wells by zone
• Surface deformation
measurement
• Tomographic fracture imaging
• Passive measurement of
seismic energy emissions
(similar to microseismic
monitoring)

98. Three monitoring wells
• Location factors:
• Access
• Predicted plume growth
• Specific tests
• Future use
• Formation logging:
• Reservoir saturation
• Sonic
• Others TBD
• Gas content:
• CO2
• Methane
• Tracers
• Core collection

99. Chattanooga Shale Study Area

100. Shale Test–
Injection and
Off-set
Monitoring Well
Locations

101. InjecFon
Well
–
4
Stage

102. P3 (CH4)
P3 (CO2)
P7 (CH4)
P7 (CO2)
P11 (CH4)
P11 (CO2)
1000
Adsorbed Gas (scf/ton, DMMF)
UFlizing
Lab
Results
to
Update
Models
350 psi
900
800
700
600
500
400
300
200
100
0
0
200
400
600
800
Pressure (psia)
1000
1200
1400

103. http://www.energy.vt.edu
THANK
YOU
Acknowledgments
Financial
assistance
for
this
work
was
provided
by
the
U.S.
Department
of
Energy
through
the
NaFonal
Energy
Technology
Laboratory's
Program
under
Contract
No.
DE-­‐
FE0006827.

104. CCS Regulatory Frameworks
Pamela Tomski, Senior Advisor Policy Regulatory - The Americas
AiChE Workshop
20 October 2013

105. Outline
•
•
•
•
•
•
Key Principles of a CCS Regulatory Regime
Storage Site Permitting
GHG Accounting and Reporting
Long-term Liability and Stewardship
New Source Performance Standards
Standards and Regulations (Steve Carpenter, ARI)

106. Key Principles of CCS Regulatory Regime
•
•
•
•
•
Comprehensiveness
Safety and environmental integrity
Public outreach and consultation
Socio-economic policies
Streamline regulation and coordination among regulatory
agencies
• Flexibility to address site-specific conditions
• Efficient use of resources and protection of property rights
Geologic storage integrity and environmental and public
safety are essential

107. Regulations must be comprehensive flexible
Pore space access and
use
Comprehensive and
flexible

108. Public outreach and consultation is key
• Know your audience –
social site characterization
to design outreach for local
conditions
• Have a two-way
conversation – address
needs and concerns of
target audience and
developer
• Effective engagement with
consistent messages is
essential and can make or
break a project

109. U.S. Storage Site Permitting
Jurisdiction
• U.S. EPA, Office of Water
Underground Injection Control
(UIC) Program
• Administered by Regional EPA
office (federal) unless state
applies for primacy
Types of Permits (CO2 Injection
Wells)
• Class VI: Geologic Sequestration
• Class II: Oil Gas / Enhanced
Oil Recovery
• Class V: Other / Experimental

110. Class II
Class VI

111. §144.19 Transitioning from Class II to VI
The Director will determine when there is an increased risk to
USDWs. The Director will consider the following:
•
•
•
•
•
•
•
Increase in reservoir pressure within the injection zone(s)
Increase in carbon dioxide injection rates
Decrease in reservoir production rates
Distance between the injection zone(s) and USDWs
Suitability of the Class II area of review delineation
Quality of abandoned well plugs within the area of review
The owner’s or operator’s plan for recovery of carbon
dioxide at the cessation of injection
• The source and properties of injected carbon dioxide
• Any additional site specific factors as determined by the
Director
Ref: Ground Water Protection Council‐UIC Conference, Sarasota, Florida: “The EPA Class VI GS Rule: Regulation and
Implementation.” http://www.gwpc.org/sites/default/files/event‐sessions/Kobelski_Bruce.pdf

112. UIC Class VI guidance documents
13 Planned, 7 Available
• Well Testing Monitoring
• Primacy Application
Implementation
• Site Characterization
• Area of Review Evaluation
Corrective Action
• Well Construction
• Financial Responsibility
• Public Participation Considerations
for GS Wells Facts
http://water.epa.gov/type/groundwater/uic/class6/gsguidedoc.cfm

113. Storage projects with RD exemptions
SECARB - Class V sought for the following reasons:
• Short duration of injection (3 years) and modest CO2 volumes
• Characterization and modeling of “stacked” CO2 storage
• CO2 injection under “real world” operating conditions
• Demonstration of experimental monitoring tools and methods

114. Status of Class VI applications primacy

115. GHG Accounting Reporting
Subpart RR - Geologic
Sequestration
• All Class VI wells or wells that inject
CO2 for long-term containment
• CO2 source, mass of CO2 transferred
•
onsite and mass injected
Fugitive, vented, leaked emissions;
annual cumulative CO2 mass stored
Subpart UU – Other, CO2 EOR
• CO2 source, mass transferred onsite
and mass injected
Subpart PP - CO2 Suppliers
• CO2 captured, extracted, exported
Mandatory Greenhouse Gas
Reporting Rule (2009)
Amendments (2010)
(FR V. 75 No. 230, December 1,
2010 at 75065)
EPA Subpart RR: http://www.epa.gov/ghgreporting/reporters/subpart/rr.html

116. GHG Accounting Reporting
US EPA, 2013 and Bruce Hill, Clean Air Task Force

117. MRV Plan (Required for RR)
• Identify active and maximum
•
•
•
•
•
monitoring areas
Identify potential CO2 surface
leakage pathways
Surface CO2 leak detection and
quantification strategy
Strategy for baseline
measurements (pre-injection)
Site-specific variables for mass
balance (reporting framework)
Site closure and post-injection
monitoring
Revise plan based on site
performance as necessary
Reporter Submits
MRV Plan
EPA Reviews
MRV Plan
EPA Technical Review
(Iterative)
EPA Decision
Reporter Implements
MRV Plan

118. Integrating RR and Class VI
• No threshold for reporting – Class VI “all in” for RR
• RR and Class VI are not fully integrated; however, they
complement each other
• The purpose of RR is to document CO2 storage
permanence through MRV; Class VI ensure protection of
USDWs
• The MRV plan may describe relevant elements of the UIC
permit (e.g. leakage pathway assessment) and how those
elements satisfy RR
• All facilities that conduct GS (RR) are required to submit
annual reports (narrative of monitoring effort) to EPA
• To date, no facilities have reported under RR

119. Long-term Liability
• No federal authority to establish funding or accept
responsibility; new legislation would be required
• Proposed bills have not passed (H. 2454 / S. 1733) –
establish task force to provide recommendations to
Congress on financial mechanisms for long-term liability

120. Long-term Liability
• Six states have addressed long-term liability; approaches to
financing long-term stewardship varies
• No funding mechanism (WA, UT, OK, WV)
• Stewardship fund; state assumes limited long-term liabilities
(KS, LA, TX, WY)
• Stewardship fund; state assumes all L-T liabilities (ND, MT)
CCSReg Project

121. GHG Limits for New Power Plants - NSPS
• Authority under Section 111 of Federal Clean Air Act
• Re-proposed CO2-NSPS (September 20, 2013) –under
60 day comment period
• New coal or petcoke “Electric Utility Steam Generation
Units” (EGUs) and IGCCs limited to 1,000 lbs of CO2/
MWh (gross) on 12 month rolling average
• Compliance is stack-based emissions (CO2 storage not
part of the calculation) and EPA’s proposal does not
involve downstream regulation
• EGU operators must send captured CO2 to storage site
that complies with Subpart RR
http://www2.epa.gov/carbon-pollution-standards/2013-proposed-carbon-pollution-standard-new-power-plants

122. NSPS - primary technology issues
“The term ‘standard of performance’ means a standard for emissions of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any nonair
quality health and environmental impact and energy requirements) the
Administrator determines has been adequately demonstrated.”
• BSER for coal is “partial CCS” – cites Kemper IGCC, Boundary
Dam, TCEP and HECA
• Bases BSER on: feasibility, costs, size of emission reduction,
“promoting further development of technology” (p. 172-174)
• Storage viability based on general geology knowledge and NETL
field tests (p. 221-224)
• Locations remote from EOR or existing pipelines are “not
expected to have new coal-fired builds without CCS in any
event…” (p. 253)

123. Standards and Regulations
• Standards can be used to support / simplify the process
of technical regulations development and application
• World’s first formally recognized CCS standard –Z-742-12
Geological Storage of Carbon Dioxide
• International Standards Organization – 31000, 17024,
14064, 14065



International Performance Assessment Centre for
Geologic Storage of CO2 – Seed document
Canadian Standards Association - ISO Secretariat,
standards developer
Bi-national agreement between USA Canada
S. Carpenter, ARI

124. Why is Z-741-12 important?
• Additional(ity) – in addition to business as usual
• Measurable – MVA, MMV, MRV
• Independently Audited – 3rd party, no OCI
• Unambiguously Owned – based clearly on
domestic and international law, no double
counting
• Address/Account for leakage – outside of the project
boundary – MVA, MMV, MRV
• Permanent – non-reversible
S. Carpenter, ARI

125. ISO TC 265 – CCS
Standardization of design, construction, operation, and
environmental planning and management, risk
management, quantification, monitoring and verification,
and related activities in the field of carbon dioxide capture,
transportation, and geological storage (CCS).
S. Carpenter, ARI

126. ISO TC 265 – CCS
• June 2012: TC-265 Organized in Paris, France
• February 2013: 2nd Plenary Meeting in Madrid, Spain
• Sept 23-25, 2013: 3rd Plenary Meeting Beijing, China
• April 2014: 4th Plenary Meeting, Berlin, Germany
• 5th Plenary Meeting TBD (hopefully, USA)
• 36 months to deliver draft standard
• 24 months to debate, ballot, and resolve issues
• US TAG is always looking for a few good experts!
S. Carpenter, ARI