AlChE-Global-CCS_Institute-Presentation-101813

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

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

Introducing the Global CCS Institute

3

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.

Globally connected membership

INSTITUTE MEMBERSHIP NUMBERS AND LOCATIONS TOTAL 378

80 136 82

3

5 74

Networking capability Expert support to Members / Projects

Comprehensive resources Best pracHce guidelines and toolkits

The Global CCS Institute – what we do

The Global Status of CCS: 2013

6

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

7

CCS/CCUS OVERVIEW: The Role of CCS/CCUS

Prepared By: Steven M. Carpenter, Vice, President

ADVANCED RESOURCES INTERNATIONAL, INC. Arlington, VA

20 October 2013

CCS/CCUS Overview: What Is It & What Are Its ImplicaHons?

8

30,000 ft view – why are we here?

CCS vs. CCUS

Major Project portfolio

Standardization is key

Presentation Topics

9

Background – Why are we here?

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

11

What is CCS?

12

What is CCS?

13

What is CCS?

14

What is CCS?

15

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

16

David Black’s Flyover

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

18

In 17 years we go from…

19

…to this…

20

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

21

What is CCS?

22

What is CCS?

23

CO2 Injection

CO2 Source Oil to

Market Production Well

CO2 Recycled

Current Water Oil Contact

Original Water

Oil Contact

Stage #1

Stage #2

Stage #3 TZ/ROZ

Unswept Area

Oil Bank

Swept Area

Integrating CO2-EOR and CO2 Storage Could Increase Storage Potential

Saline Reservoir

24

LaBarge Gas Plant

Val Verde Gas Plants

Enid FerFlizer Plant

Jackson Dome

McElmo Dome Sheep Mountain Bravo Dome

13

5

17 70

6

Dakota Coal GasificaFon

Plant

Antrim Gas Plant

2 1

3

  120 CO2-EOR projects provide 352,000 bbl/day

  New CO2 pipelines are expanding CO2-EOR to new oil fields and basins.

  320 mile Green Pipeline

  226 mile Encore Pipeline

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

ExisHng CO2 Pipeline

CO2 Pipeline Under Development

120

Encore Pipeline

Denbury/Green Pipeline

U.S. CO2-‐EOR AcFvity – Oil Fields & CO2 Sources

Lost Cabin Gas Plant

1

25

Significant Volumes of CO2 Are Already Being Injected for EOR in the U.S.

* 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)

Location of EOR / Storage CO2 Source Type and Location

CO2 Supply (MMcfd)

Geologic Anthropogenic Texas, New Mexico, Oklahoma, Utah

Geologic (Colorado, New Mexico) Gas Processing, Fertilizer Plant (Texas) 1,600 190

Colorado, Wyoming Gas Processing (Wyoming) - 300

Mississippi Geologic (Mississippi) 930 - Michigan Gas Processing (Michigan) - 10

Oklahoma Fertilizer Plant (Oklahoma) - 35 Saskatchewan Coal Gasification (North Dakota) - 150 TOTAL (MMcfd) 2,530 685 TOTAL (MMt per year) 49 13

26

Oil Recovery & CO2 Storage From "Next GeneraFon" CO2-‐EOR Technology*

Reservoir Setting Oil Recovery*** (Billion Barrels)

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

27

Num

ber o

f 1 G

W S

ize C

oal-F

ired

Powe

r Plan

ts*

0

200

300

100

240

133

Technical Demand/ Storage Capacity

Economic Demand/ Storage Capacity**

*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).

Total CO2 Anthropogenic CO2 Total CO2 Anthropogenic CO2

228

121

Reservoir Setting

Number of 1GW Size Coal-Fired

Power Plants***

Technical Economic*

L-48 Onshore 170 90

L-48 Offshore/Alaska 31 14

Near-Miscible CO2-EOR 5 1

ROZ** 34 28

Sub-Total 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.

Demand for CO2: Number of 1 GW Size Coal-‐Fired Power Plants

28

Linking CO2 Supplies with CO2-‐EOR Demand

Sources: EIA Annual Energy Outlook 2011 for CO2 emissions; NETL/Advanced Resources Int’l (2011) CO2 demand.

The primary EOR markets for excess CO2 supplies from the Ohio Valley, South AtlanFc and Mid-‐ConFnent is East/West Texas and Oklahoma.

4.2 0.3

Pacific

0

0.2

0.2

7.4

14.2 4.3

2.0

6.3 3.7

3.7

0.2 2.3

13 Bcfd

19 Bcfd

0.2

3.6

8.0

-‐

0.6 4.2

4.2

0.3 8 Bcfd

Region

Captured CO2

Supplies*

CO2

Demand

Excess CO2

Supply

Net CO2

Demand(BMt) (BMt) (BMt) (BMt)

New England 0.2 - 0.2

Middle Atlantic 2.3 0.2 2.1

South Atlantic 7.4 0.2 7.2

East North Central 4.2 0.6 3.6

West North Central 6.3 2.0 4.3

East South Central 3.6 0.2 3.3

West South Central 4.3 14.2 9.9

Mountain 3.7 3.7

Pacific 0.3 4.2 3.8

Total 32.2 25.3 20.8 13.7

ROZ "Fairways" 8.0 8.0JAF2012_035.XLS

Captured CO2 Supplies and CO2 Demand

* Capture from 200 GW of coal-fired power plants, 90% capture rate.

CO2 Demand by EOR (Bmt) Captured CO2 Emissions (Bmt)

Jackson Dome

29

CO2-EOR Global Potential

Region Name Basin Count

Asia Pacific 8 Central and South America 7 Europe 2 Former Soviet Union 6 Middle East and North Africa 11 North America/Other 3 North America/United States 14 South Asia 1 S. Africa/Antarctica 2 Total 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

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.

32

Major CCS Project Poriolio

33

Major CCS Demonstration Projects CCPI ICCS Area 1 FutureGen 2.0

Southern Company Kemper County IGCC Project

Novel Transport Gasifier w/Carbon Capture DOE Share: $270M

EOR – ~3.0 M TPY 2014 start

NRG W.A. Parish Generating Station

Post CombusHon CO2 Capture DOE Share: $167M

EOR – ~1.4M TPY 2016 start

Summit TX Clean Energy Commercial Demo of Advanced IGCC w/ Full Carbon Capture

DOE Share: $450M EOR – ~2.2 TPY 2017 start

HECA Commercial Demo of Advanced IGCC w/ Full Carbon Capture

DOE Share: $408M EOR – ~2.6M TPY 2019 start

Leucadia Energy CO2 Capture from Methanol Plant

DOE Share: $261M EOR – ~4.5 M TPY 2017 start

Air Products and Chemicals, Inc. CO2 Capture from Steam Methane Reformers

DOE Share: $284M EOR – ~0.93M TPY 2012 start

FutureGen 2.0 Large-‐scale TesHng of Oxy-‐CombusHon

DOE Share: Plant -‐ $1.04B SALINE – 1M TPY 2017 start

Archer Daniels Midland CO2 Capture from Ethanol Plant

DOE Share: $141M SALINE – ~0.9M TPY 2014 start

34

RCSP Phase III: Development Projects

8

7

1

2

6

5

9

Partnership Geologic Province Target Injection Volume (tonnes)

Big Sky Nugget Sandstone 1,000,000

MGSC Illinois Basin- Mt. Simon Sandstone 1,000,000

MRCSP Michigan Basin- Niagaran Reef 1,000,000

PCOR

Powder River Basin- Bell Creek Field 1,500,000

Horn River Basin- Carbonates 2,000,000

SECARB

Gulf Coast – Cranfield Field- Tuscaloosa

Formation 3,400,000

Gulf Coast – Paluxy Formation 250,000

SWP Regional CCUS Opportunity 1,000,000

WESTCARB Regional Characterization

InjecFon Ongoing

2013 InjecFon Scheduled

InjecFon Scheduled 2013-‐2015

1

2

7

8

6

9

5

  Large-‐volume tests   Four Partnerships currently injec9ng CO2   Remaining injec9ons scheduled 2013-‐2015

InjecFon began Nov 2011

InjecFon Started April 2009

Core Sampling Taken

InjecFon began August 2012

InjecFon started in depleted reef February 2013

InjecFon Started June 2013

Seismic Survey

Completed

3

3

4

4

35

Global Portfolio

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

37

Importance of CCUS (CO2-EOR)

•  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)   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

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.”

38

StandardizaFon

39

EPA’s Regulatory “Train Wreck”

Source: Edison Electric InsFtute; Dick Winschel, CONSOL Energy

40

CCS Regulatory “Train Wreck”

41

TC-265 Working Groups

TC-‐265

Capture Transport Storage QuanFficaFon & VerificaFon Crossculng CO2-‐EOR

Twined Secretariat

42

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: [email protected]

http://adv-res.com/

Thank you

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

Defining Carbon Capture

The Cost Driving Step in CCS / CCUS

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

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

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

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)

Large scale integrated CCS projects (LSIPs)

Wide variety of capture options being planned

Projects by capture type and industry

0 5 10 15 20 25 30 35 40 45 Number of projects

Pre-combustion (gasification) Pre-combustion (natural gas processing) Post-combustion Oxy-fuel combustion Industrial separation Various/Not decided

Power generation

Industrial applications

Significant amounts of CO2 are already being captured and stored

0 10 20 30 40 50 60

Other industries

Natural gas processing

Power generation

Mass of CO2 (Mtpa)

Identify Evaluate Define Execute Operate

CO2 captured by industry and project development stage

Regional variations exist in preferred capture technology

0 5 10 15 20 25

Africa

South America

Other Asia

Middle East

Australia

Canada

China

Europe

United States

Number of projects

Pre-combustion (gasification) Pre-combustion (natural gas processing)

Post-combustion Oxy-fuel combustion

Industrial separation Various/Not decided

Projects by location and capture type

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

Capture R&D

Provides Promise of Driving Down Capture Costs

Solvent Based Process

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

Sorbent Based Process

•  Physi or Chemi sorption based process •  Packed or Fluidized Beds •  Lower pressure or increase temperature to regenerate

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

Relative Maturity of Capture Technologies

DOE/NETL’s Exis-ng Plants R&D Program –Carbon Dioxide, Water, & Mercury, June 2010

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

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

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

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

SECARB’s Early Test Cranfield, Mississippi

64

SECARB Early Test Monitoring Large Volume Injection at Cranfield

Natchez Mississippi

Mississippi River

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

Cranfield Early Test Monitoring: Detailed Area of Study

66

67

4,146,143

8,073,395

3,927,251

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

Jul-‐0

8Sep-‐08

Nov-‐08

Jan-‐09

Mar-‐09

May-‐09

Jul-‐0

9Sep-‐09

Nov-‐09

Jan-‐10

Mar-‐10

May-‐10

Jul-‐1

0Sep-‐10

Nov-‐10

Jan-‐11

Mar-‐11

May-‐11

Jul-‐1

1Sep-‐11

Nov-‐11

Jan-‐12

Mar-‐12

May-‐12

Jul-‐1

2Sep-‐12

Nov-‐12

Jan-‐13

Mar-‐13

May-‐13

Jul-‐1

3

CO2

(Metric

Tons)

Time

Cumulative CO2 InjectedJuly, 2013

CumulativeTotal

Cumulative VolumeInjected West

Cumulative VolumeInjected East

SECARB Early Test: Cumulative CO2 Injected, July 2013

68

4,377,834

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

Jul-‐0

8Sep-‐08

Nov-‐08

Jan-‐09

Mar-‐09

May-‐09

Jul-‐0

9Sep-‐09

Nov-‐09

Jan-‐10

Mar-‐10

May-‐10

Jul-‐1

0Sep-‐10

Nov-‐10

Jan-‐11

Mar-‐11

May-‐11

Jul-‐1

1Sep-‐11

Nov-‐11

Jan-‐12

Mar-‐12

May-‐12

Jul-‐1

2Sep-‐12

Nov-‐12

Jan-‐13

Mar-‐13

May-‐13

Jul-‐1

3

CO2

(Metric

Tons)

Time

Cranfield Net CO2 StoredJuly, 2013

CO2 Stored

SECARB Early Test: Cranfield Net CO2 Stored, July 2013

August 6, 2012 JAF2012_081.PPT

Midwest/Ohio Valley Regional Attributes and CO2 Utilization Opportunities

69

LaBarge Gas Plant

Val Verde Gas Plants

Enid FerFlizer 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

ExisFng CO2 Pipeline

CO2 Pipeline Under Development

119

Encore Pipeline

Denbury/Green Pipeline

U.S. CO2-EOR Activity

Lost Cabin Gas Plant

1

http://www.netl.doe.gov/energy-analyses/pubs/NextGen_CO2_EOR_06142011.pdf

Financial & Production Benefits from “Next Generation” CO2-EOR

xx

NETL Next Generation CO2 Oil Recovery

71

0

5

10

15

20

25

Bill

ion

Tons

of C

O2

CO2 Requirements

Natural Anthropogenic 0

10

20

30

40

50

60

70

80

CO

2 O

il R

ecov

ery

Bill

ion

BB

L

CO2 Oil Recovery

Billion Barrels Oil

Context - Total Proven US Oil Reserves @ 2010 = 30.9 Billion BBL BP Annual Statistical Review - 2011

SECARB’s Anthropogenic Test Citronelle, Alabama

72

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

CO2 absorption

Solv

ent

Reg

ener

atio

n

Compression Solvent

Management

Gas

Con

ditio

ning

Plant Barry Capture Unit: 25MW, 500 TPD

74

Start with a Good Storage Site

75

•  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)

SECARB Citronelle: MVA Sample Locations

76

• 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

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78


79

SECARB Citronelle: MVA & Closure

80

Baseline 1 year

Injection 2 years

Post 3 years

APR 2011 to AUG 2012 SEPT 2012 to SEPT 2014 OCT 2014 to SEPT 2017

  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

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

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

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

CBM and ECBM Mechanisms Coalbed Methane ProducFon

(CBM) Enhanced Coalbed Methane

ProducFon (ECBM)

(i)  Dewatering: pressure , effecFve stress , fracture apertures permeability

(ii)  CH4 releasematrix shrinkage and zero volume change condiFon, fracture apertures , permeability

•  Net Permeability: CompeFng effects (i)-‐(ii)

(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

CO2

CH4

Gas C

ontent

PL Pressure

Under saturated

VL

VL/2 Dewatering

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)

3rd HydraulicFracture Zone

4th HydraulicFracture Zone

2nd HydraulicFracture Zone

1st HydraulicFracture Zone

InjectionWell Monitoring

Well

MonitoringWell

!

Russell County -‐ Coal Seams Stage 4

Greasy Creek 1 Seaboard 2

Lower Seabord 1&2 Lower Seaboard 3

Upper Horsepen 2&3 Stage 3

Middle Horsepen 1 Middle Horsepen 2

Pocahontas 11 Pocahontas 10

Lower Horsepen 1 Lower Horsepen 2

Stage 2 Pocahontas 9

Pocahontas 8-1 Pocahontas 8-2

Pocahontas 7-1A Pocahontas 7-1B Pocahontas 7-2 Pocahontas 7-3

Stage 1 Pocahontas 6 Pocahontas 5

Pocahontas 4-1 Pocahontas 4-2 Pocahontas 3-1 Pocahontas 3-4

9.6 m (3 ft)

9.8 m (3 ft)

9.3 m (2.8 ft)

7.6 m (2.3 ft)

RU-84 BD114

CO2 InjecHon

CO2 InjecFon

0

100

200

300

400

500

600

700

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900

1000

01/09

/09 11

01/12

/09 11

01/15

/09 10

01/18

/09 10

01/21

/09 10

01/24

/09 10

01/27

/09 10

01/30

/09 10

02/02

/09 10

02/05

/09 10

02/08

/09 10

Inje

ctio

n Pr

essu

re (p

sia)

Tem

pera

ture

(Deg

rees

F)

0

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70

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100

CO

2 In

ject

ion

Rat

e (to

ns/d

ay)

Injection Well (psia)CO2 Process Temperature (F)CO2 Injection Rate (tons/day)

January 21, 2009 -‐ 500 ml of the PTMCH tracer

Tracer Injec-on

Miskovic, 2011

Russell County Flowback

0

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05/20/09

06/19/09

07/20/09

08/19/09

09/19/09

10/19/09

11/19/09

12/19/09

01/19/10

02/18/10

03/21/10

04/20/10

05/21/10

06/20/10

07/21/10

08/20/10

09/20/10

10/20/10

11/20/10

12/20/10

01/20/11

02/19/11

03/22/11

Gas C

ompo

siHo

n (%

)

Gas P

rodu

cHon

(Mcf/day)

BD-‐114 Flowback Carbon Dioxide Methane Nitrogen

Shut-in Period with CO2 Injection mid November ‘08 – mid May ‘09

Pre CO2 Injection EUR = 319 MMcf

Post CO2 Injection EUR = 534 MMcf

CO2 InjecFon Decline-‐Curve Analysis Phase II InjecFon Well RU-‐84 (BD-‐114)

Gas

Pro

duct

ion,

M

cf/m

onth

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

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

Scheduled October 2013

Field demonstration in Buchanan County, VA

CO2 Plume by Layer

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)

.

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

Chattanooga Shale Study Area

Shale Test– Injection and ��

Off-set Monitoring Well

Locations

InjecFon Well – 4 Stage

UFlizing Lab Results to Update Models

0

100

200

300

400

500

600

700

800

900

1000

0 200 400 600 800 1000 1200 1400Pressure (psia)

Ads

orbe

d G

as (s

cf/to

n, D

MM

F)

P3 (CH4) P3 (CO2) P7 (CH4) P7 (CO2) P11 (CH4) P11 (CO2)

350 psi

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.

http://www.energy.vt.edu

Pamela Tomski, Senior Advisor Policy & Regulatory - The Americas AiChE Workshop 20 October 2013

CCS Regulatory Frameworks

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)

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

Regulations must be comprehensive & flexible

Pore space access and use

Comprehensive and flexible

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

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

Class II & Class VI

§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

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

Storage projects with R&D 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

Status of Class VI applications & primacy

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

EPA Subpart RR: http://www.epa.gov/ghgreporting/reporters/subpart/rr.html

Mandatory Greenhouse Gas Reporting Rule (2009) Amendments (2010) (FR V. 75 No. 230, December 1, 2010 at 75065)

US EPA, 2013 and Bruce Hill, Clean Air Task Force

GHG Accounting & Reporting

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

Reporter Submits MRV Plan

EPA Reviews MRV Plan

EPA Technical Review (Iterative)

EPA Decision

Reporter Implements MRV Plan Revise plan based on site

performance as necessary

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

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

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

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

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)

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

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

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

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

Business

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