11

Prepared for:

RECS

Prepared by:

George J. Koperna, Jr., Vice President

Advanced Resources International, Inc.

June 10, 2015

University of Alabama at Birmingham

Storage, Integrity, Monitoring and the

SECARB Storage Project

22

Disclaimer

This presentation is based upon work supported by the Department of Energy

National Energy Technology Laboratory under DE-FC26-05NT42590 and was

prepared as an account of work sponsored by an agency of the United States

Government. Neither the United States Government nor any agency thereof,

nor any of their employees, makes any warranty, express or implied, or

assumes any legal liability or responsibility for the accuracy, completeness, or

usefulness of any information, apparatus, product, or process disclosed, or

represents that its use would not infringe privately owned rights. Reference

herein to any specific commercial product, process, or service by trade name,

trademark, manufacturer, or otherwise does not necessarily constitute or imply

its endorsement, recommendation, or favoring by the United States

Government or any agency thereof. The views and opinions of authors

expressed herein do not necessarily state or reflect those of the United States

Government or any agency thereof.

3

Background

4

SECARB Phase III Projects

5

Storage Overview

The CO2 capture unit at Alabama Power’s(Southern Co.) Plant Barry became operationalin 3Q 2011.

A newly built 12 mile CO2 pipeline from PlantBarry to the Citronelle Dome was completed in4Q 2011.

A characterization well was drilled in 1Q 2011to confirm geology.

Injection wells were drilled in 3Q 2011.

114k metric tons were injected into the Paluxyformation beginning in the 3Q 2012.

Injection operations were terminated September 3Q 2014

3 years of post-injection monitoring.

Project Schedule and Milestones

6

Project Objectives

1. Support the United States’ largest commercial prototype CO2 capture and transportation

demonstration with injection, monitoring and storage activities;

2. Test the CO2 flow, trapping and storage mechanisms of the Paluxy Formation, a regionally

extensive Gulf Coast saline formation;

3. Demonstrate how a saline reservoir’s architecture can be used to maximize CO2 storage

and minimize the areal extent of the CO2 plume;

4. Test the adaptation of commercially available oil field tools and techniques for monitoring

CO2 storage (e.g., VSP, cross-well seismic, cased-hole neutron logs, tracers, pressure,

etc.);

5. Test experimental CO2 monitoring activities, where such technologies hold promise for

future commercialization;

6. Begin to understand the coordination required to successfully integrate all four components

(capture, transport, injection and monitoring) of the project; and

7. Document the permitting process for all aspects of a CCS project.

7

Coordination is a Full Time Job!

8

Geology

9

Injection/Storage Site Geology

Proven four-way closure at Citronelle

Dome

Injection site located within Citronelle

oilfield where existing well logs are

available

Deep injection interval (9,400 ft)

Numerous confining units

Base of USDWs ~1,400 feet

Existing wells cemented through primary

confining unit

>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)

No evidence of faulting or fracturing,

based existing 2D seismic lines.

10

Collected new geologic data on the Paluxy reservoir and confining

unit with the drilling of the project’s three new wells:

• 210 feet of whole core and 70 percussion sidewall cores

• Full set of open hole logs on all three wells (quad combo, MRI, spectral gamma,

mineralogical evaluation, waveform sonic, cement quality, pulsed neutron

capture)

• Baseline vertical seismic profiles and cross-well seismic collected in Feb 2012

• Analysis of over 80 existing oilfield

well logs for porosity, thickness

and depositional style.

• Sand mapping to determine “open”

or “closed” sand units.

Baseline Reservoir Characterization:

Geologic Characterization

11

Extrapolated Continuity of

Upper Paluxy Sandstones

At Citronelle Southeast Unit

Northwest - Southeast

12

Paluxy Sandstone Section of the D-9-7#2 core (9,598 to 9,607ft)

• Fine to medium coarse-grained

fluvial sandstones.

• Grains are sub-round, moderately

well sorted, predominately quartz.

• Occasional clay pebble

conglomerate and rip-up clasts at

base of fluvial channel

sequences.

• Burrowed to bioturbated

sandstone at top of channel

sequences.

• Mottled red-brown to light gray.

• Sandstone permeability generally

correlates to grain size.

680

mD

1.6

Darcy

1.8

Darcy

600

mD

1

Darcy

730

mD

1.1

Darcy

860

mD

0.27

mD

279

mD

13

Shale Rock Properties (D-9-9#2)

•CO2 Adsorption Isotherm Test

•TOC

Shale Sample sent to UAB ‘s Caprock Laboratory for Analysis

7.76%

0.002

mD

8.62%

0.008

mD

8.56%

0.004

mD

8.96%

0.011

mD

7.76%

0.004

mD

7.43%

0.06 mD

7.23%

(Perm n/a)

8.99%

0.006

mD

Paluxy

Mudstone D-9-9 #2

Core: 9,424’ - 9,434’• Low permeability mudstones

provide local confining layers and flow baffles between reservoir sandstones.

14

Permitting

15

Permitting Outline

National Environmental Protection Act (NEPA)

Alabama Historical Commission

U.S. Fish and Wildlife

U.S. Army Corps of Engineers

Alabama Department of Environmental Management

(ADEM)

16

National Environmental Protection

Act (NEPA)

Categorical Exclusion: All locations performing office work, planning,

coordination, etc.

Environmental Assessment (EA)

– Environmental Information Volume and Supplements for Storage Project, Pipeline

and Electric Transmission Line

– Finding of No Significant Impact (FONSI) issued by NETL on March 18, 2011

Environmental Impacts

17

Alabama Historical Commission

2 cultural resources assessments

4 archaeological sites discovered in the

Transmission Line survey, though not

eligible under the National Register of

Historic Places

– no further investigations warranted

No cultural resources were discovered

– no further investigations warranted

Following review of EA, “…agree with

the EA as it pertains to no effect to

National Register eligible cultural

resources” by State Historic

Preservation Officer, April 2011

18

U.S. Fish and Wildlife

U.S. Fish and Wildlife permit and NEPA compliance mandate the protection of

threatened and endangered species

– Potential impacts to an threatened species and its habitat (Gopher Tortoise)

– Over 100 tortoise burrows encountered long pipeline easement, over 30

actively inhabited gopher tortoise burrows

– Directional drilling under tortoise burrows/colonies less expensive than

temporary relocation (would have cost $2MM for relocation of all turtles)

– Burrows identified at or near most well sites

– Avoid drilling/monitoring activities in proximity to burrows

19

U.S. Army Corps of Engineers

Army Corps of Engineers permit covers

wetland impacts due to pipeline and injection

site construction

Pipeline route

– 12 miles

– Directional drilled 18 sections of the

pipeline, 30-60 ft deep, under wetlands,

roads, utilities, railroad tracks, and tortoise

colonies

– Surface re-vegetation and erosion control

Well pad construction

– Wetlands impacts mitigated after drilling

completed

20

EPA UIC Class V Permit

A Class V Experimental Well permit was sought for the following reasons

– Short duration of injection (3 years) and modest volumes of CO2

– Characterization and modeling of “stacked” CO2 storage

– CO2 Injection Under “real world” operating conditions

– Demonstration of experimental monitoring tools and methods

After comments by EPA, most Class VI (CO2 sequestration well) standards were applied

– Injection Area of Review (AOR) determined by modeling and monitoring results

– Extensive deep, shallow and surface CO2 monitoring

– Injection stream monitoring

– Periodically updated Corrective Action Plan

– Site closure based on USDW non-endangerment demonstration (5-yr renewal)

– Pressurized annulus throughout injection (+/- 200 psig)

Class V Experimental injection permit was awarded in November 2011, eleven months after initial draft application

Permission to operate issued in August 2012

21

Monitoring

22

UIC MVA Elements and Frequency

Continuous Monthly Quarterly Annual

Milestone

(Baseline,

Injection,

Post)

Shallow

Soil flux

Groundwater sampling (USDW)

PFT survey

Deep

CO2 volume, pressure & composition

Reservoir fluid sampling

Injection, temperature & spinner logs

Pulse neutron logs

Crosswell seismic

Vertical seismic profile (VSP)

Experimental

Distributed Temperature Sensing (DTS)

Comparative fluid sampling methods

MBM VSP

Distributed Acoustic Sensing (DAS)

MBM VSP & OVSP Seismic

MVA Method

Frequency

23

CO2 Injection and Storage Site

CO2 Monitoring, Verification and

Accounting

• One new injector (D-9-7 #2)

• Two new deep observation

wells (D-9-8 #2 & D-9-9 #2)

• Two in-zone & above zone

monitoring wells (Citronelle

wells D-4-13 & D-4-14)

• One PNC logging well (D-9-11)

• 12 soil flux monitoring

locations

• PFT monitoring on nine well

pads

24

Shallow MVA

Inoculation

Well/Sample AUG 2012 JUN 2013 NOV 2013

D-9-1 ND ND ND

D-9-2 ND ND ND

D-9-3 ND ND ND

D-9-6 ND ND ND

D-9-7-1 ND ND ND

D-9-8 Invalid Data ND ND

D-9-9 ND ND ND

D-9-10 Invalid Data ND ND

D-9-11 ND ND NDAir Blank 1 ND NST NST

System Blank ND ND

Testing

Soil Flux Sampling Results

USDW Groundwater Sampling

3 - Background Monitoring Events:

January 2012 (N=1) through July 2012

(N=3)

10 - Injection Period Monitoring Events:

November 2012 (N=4) through February

2015 (N=13)

Background anomalies of Mn, Fe, and Cl

above UIC permit discharge limits.

To evaluate the potential exceedance of

regulatory standard (e.g., UIC permit

discharge limit), the EPA GW Unified

Guidance recommends statistical

comparisons (“value to value” comparison

to standard and evaluation of changes

between baseline and monitoring)

Quarterly testing to continue throughout the

PISC

PFT Survey

25

Deep MVA CO2 Injection History

CO2 Stream composition data (%)

CO2 O2 N2 Total

Nov-13 99.968 0.003 0.029 100

Oct-13 99.971 0.002 0.027 100

Sep-13 99.950 0.007 0.043 100

Aug-13 99.984 0.003 0.013 100

Jul-13 99.893 0.031 0.076 100

Jun-13 99.893 0.031 0.076 100

May-13 99.976 0.003 0.021 100

Apr-13 99.977 0.003 0.020 100

Mar-13 99.977 0.003 0.020 100

Feb-13 99.977 0.003 0.020 100

Jan-13 99.978 0.004 0.018 100

Dec-12 99.981 0.016 0.003 100

Nov-12 99.984 0.014 0.002 100

Oct-12 99.984 0.014 0.002 100

Sep-12 99.979 0.011 0.010 100

Aug-13 99.975 0.004 0.021 100

average 99.965 0.010 0.025

Aug-12

26

Deep MVA

D-9-8#2 Downhole Pressure

D9-8#2

D4-14In Zone

D4-13Above

Confinement

CO2 Injected

The system, as expected, is getting

more compressible with continued

injection. As a result, the pressure

transient travel time between the

injection and observation wells

continues to grow.

27

Deep MVAPlume Image Comparison with Spinner Surveys

Sand Nov 2012 Aug 2013 Oct 2013

Unit Bottom Top Thickness Flow % Flow % Flow %

J 9,454 9,436 18 14.8 18.7 16.7

I 9,474 9,460 14 8.2 20.4 19.6

H 9,524 9,514 10 2.8 7.4 7.7

G 9,546 9,534 12 2.7 2.1 0.9

F 9,580 9,570 10 0.0 1.2 1.2

E 9,622 9,604 18 26.8 23.5 30.8

D 9,629 9,627 2 0.0 0.0 0.0

C 9,718 9,698 20 16.5 11.8 10.3

B 9,744 9,732 12 4.9 0.6 0.4

A 9,800 9,772 28 23.3 14.3 12.4

Sand Unit Properties (ft)

A

B

C

D

E

F

G

H

I

J

• Time-lapse image

shows CO2 plume

located primarily in

Paluxy sands F-H

• October 2013 spinner

survey show these

sands taking only 10%

of the flow

28

Deep MVAComparison of Crosswell Reflectors

Reflection data from the repeat survey are of poor quality and limited use.

Likely cause is interference by tube waves moving up and down the well

Inje

cti

on

Zo

ne

Confining Zone

Strong, continuous

reflectors

Weak and/or

discontinuous reflectors

No reflector was

detected at or

near the top of

the CO2 where

one should be

present

Repeat

Tomogram

Baseline

Tomogram

29

Time-Lapse Differencing Using the

Baseline and Repeat Velocity Tomograms

Inje

cti

on

Zo

ne

Confining Zone

Pixelized difference tomography results without seismic

reflection overlay showing positive velocity differences

in warm colors and negative differences in cool colors

• First arrivals from repeat survey

were of sufficient quality to

produce a velocity difference

image (right) showing regions

where seismic velocity has

changed over time

• Time-lapse difference image

indicates a decrease in seismic

velocity in the upper injection

zone of up to 3%, suggesting an

increase in CO2 saturation

More importantly, no negative velocity

anomalies are observed in or above

the confining unit…implying no

detectable leakage out of inj. zone

No significant negative

velocity anomalies

Decrease in velocity

(negative anomaly)

30

MBM Geophone Array: Baseline VSP,

OVSP and Walkaway

Map of

VSP

shot

points

Next Step:

Resolution Comparison

• Crosswell ~ 10 feet

• Full VSP ~ 25 – 30 feet

• MBM VSP~ 50 feet

• Establish “fence post”

• Collect time lapse

seismic events

• Collaborative analysis of

varying resolutions

31

MBM Design: Flat-Pack & Geophone

32

Reservoir Modeling

33

Elevation and thickness maps

generated using Petra software

based on available logs

– Divided the interval

between the various sand

flow units and their

associated shaly

interburden units

– Layers further subdivided

to adequately represent

the injection well

perforations and

heterogeneity

• Grid blocks are 400’ by 400’

(before refinement)

52 layers

Model 3D View

Note: Vertical to Horizontal Ratio Exaggeration of 10

Injector

D9-7#2

Monitoring Wells (D4-

13, D4-14 and D9-

8#2)Monitoring

Well D9-8#2

34

Perforation Data

Depth from

Model

Thickness

from Model

Model

Layer

Perforated

Layer

9460 A1 9420.1 7.93 6

9460 A2 9428.0 7.93 7

9460 A3 9436.0 7.93 8 X

9460 B 9443.9 9.5 9 X

9460 C 9453.4 7.7 10

9460 D 9461.1 11.8 11 X

9460 E 9472.9 9.6 12

Interburden 9460 to

95209482.5 22.9 13

9520 A1 9505.4 7.45 14

9520 A2 9512.9 7.45 15 X

9520 B1 9520.3 4.5 16 X

9520 B2 9524.8 4.5 17

9520 C 9529.3 4.1 18

Interburden 9520 to

95409533.4 3.3 19

9540 A 9536.7 5 20 X

9540 B1 9541.7 5.6 21 X

9540 B2 9547.3 5.6 22

9540 C 9552.9 4.4 23

Interburden 9540 to

95709557.3 12.5 24

9570 Top 9569.8 6.2 25 X

9570 B 9576 8.7 26

9570 C 9584.7 4.1 27

Interburden 9570 to

96209588.8 8.6 28

9620 A1 9597.4 5.5 29

9620 A2 9602.9 5.5 30 X

9620 B 9608.4 8.3 31 X

9620 C1 9616.7 4.2 32 X

9620 C2 9620.9 4.2 33

9620 C3 9625.2 4.2 34 X

9620 D 9629.4 8.7 35

9620 E 9638.1 5.7 36

Interburden 9620 to

96709643.8 16.4 37

9670 9660.2 27.3 38

Interburden 9670-9710 9687.5 12.6 39

9710 A 9700.1 18 40 X

9710 B 9718.1 3.2 41

9710 C 9721.3 5.1 42

Interburden 9710 to

97409726.4 6.8 43

9740 A 9733.2 6.7 44 X

9740 B 9739.9 4 45 X

9740 C 9743.9 16.3 46

Interburden 9740 to

98009760.2 20.6 47

9800 A 9780.8 4.6 48 X

9800 B 9785.4 4.7 49 X

9800 C 9790.1 13.3 50 X

9800 D 9803.4 9.6 51

9800 E 9813.0 52

Sand

Name

Perforated

Intervals (ft)

Total Perf

Footage

94609436 - 9454,

9460 -947428

9520 9514 -9524 10

9540 9534 - 9546 12

9570 9570 - 9580 10

96209604 - 9622,

9627 - 962920

9670 N/A N/A

9710 9698 - 9718 20

9740 9732 - 9744 12

9800 9772 - 9800 28

9840 N/A N/A

9900 N/A N/A

9970 N/A N/A

10030 N/A N/A

10040 N/A N/A

10100 N/A N/A

10130 N/A N/A

10310 N/A N/A

10370 N/A N/A

10400 N/A N/A

10470 N/A N/A

10500 N/A N/A

Perforated intervals

respected in the model

35

Permeability and

porosity values from

core plugs were

available for sand

packages 9570 and

9620 at the D 9-7#2

(injector) and for sand

package 9460 at the D

9-8#2 well.

When no core data

were present, density-

neutron porosity and

their equivalent

permeability values

(determined by cross-

plots) were used.

Permeability and Porosity

LayerPerforated

Layer

Model

Porosity

Model

Permeability

9460 A1 0.178 14.1

9460 A2 0.195 56.9

9460 A3 X 0.169 12.5

9460 B X 0.190 45.0

9460 C X 0.200 187.5

9460 D X 0.208 37.6

9460 E 0.212 40.1

9520 A1 0.185 1.2

9520 A2 X 0.185 1.2

9520 B1 X 0.217 17.2

9520 B2 0.217 17.2

9520 C 0.170 0.7

9540 A X 0.208 18.9

9540 B1 X 0.195 4.4

9540 B2 0.195 4.4

9540 C 0.161 0.5

9570 Top X 0.150 1.3

9570 B 0.130 1.6

9570 C 0.150 1.9

Interburden 9460 to 9520

Interburden 9520 to 9540

Interburden 9540 to 9570

LayerPerforated

Layer

Model

Porosity

Model

Permeability

9620 A1 0.218 67.1

9620 A2 X 0.193 48.1

9620 B X 0.193 48.1

9620 C1 X 0.193 48.1

9620 C2 0.210 493.8

9620 C3 X 0.183 87.5

9620 D 0.200 66.9

9620 E 0.167 35.6

9670 0.170 3.3

9710 A X 0.191 28.8

9710 B 0.195 20.0

9710 C 0.180 16.5

9740 A X 0.179 7.0

9740 B X 0.200 23.6

9740 C 0.191 14.4

9800 A X 0.185 42.0

9800 B X 0.196 76.5

9800 C X 0.175 23.0

9800 D 0.187 47.0

9800 E 0.143 2.4

Interburden 9710 to 9740

Interburden 9740 to 9800

Interburden 9570 to 9620

Interburden 9620 to 9670

Interburden 9670-9710

36

Vertical permeability

measured on 9 samples was

found to be on average 4

times smaller than horizontal

permeability: ratio

implemented in the model.

Directional core data on 7

samples showed an average

horizontal anisotropy of 2 but

with an unknown direction.

Vertical & Directional Permeability

Sample Depth Net Confining Porosity Permeability

Number Stress (psig) (%) Klinkenberg (md)

8H 9577.20 1200.00 17.38 34.71

8V 9577.4 - 1200.00 17.21 17.78

9577.50

28H 9597.35 1200.00 21.62 496.23

28V 9597.45 - 1200.00 22.04 462.93

9597.65

29H 9598.35 1200.00 20.20 74.82

29V 9598.45 - 1200.00 19.90 14.14

9598.70

46H 9614.65 1200.00 20.27 167.32

46V 9615.05 - 1200.00 18.07 32.27

9615.30

49H 9617.65 1200.00 17.71 52.28

49V 9618.1 - 1200.00 16.83 6.98

9618.25

52V 9621.2 - 1200.00 20.83 756.16

9621.35

55V 9624.25 - 1200.00 20.42 535.71

9624.45

59H 9627.65 1200.00 13.70 26.50

59V 9627.8 - 1200.00 20.74 612.96

9628.10

61H 9629.75 1200.00 17.06 223.67

61V 9630.05 - 1200.00 12.37 0.80Note: Vertical to Horizontal Exaggeration Ratio of 15

37

Relative Permeability Curves

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Kr

Sw

Laboratory versus Simulation Curves

Simulation Krw Simulation Krg Krg Sample 16 (2012) Krw Sample 16 (2012) Krg Sample 36

Krw Sample 36 Krg Sample 16 (2011) Krw Sample 16 (2011) Krg Sample 46 Krw Sample 46

38

Injection Rate Match

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

7/1/2012 7/1/2013 7/1/2014

Gas

Rat

e, s

cfd

CO2 Injection Rate

Simulation Injection Rate Actual Injection Rate

39

Pressure at Monitoring Well D 9-8

4,300

4,320

4,340

4,360

4,380

4,400

4,420

4,440

4,460

4,480

4,500

Pre

ss

ure

, ps

ia

D9-8 Bottom Gauge D9-8 Top Gauge Simulation Data

Until end of injection – September 1st, 2014

4,300

4,320

4,340

4,360

4,380

4,400

4,420

4,440

4,460

4,480

4,500

Pre

ss

ure

, ps

ia

D9-8 Bottom Gauge D9-8 Top Gauge Simulation Data

Until September 1st, 2017

40

Pressure at Monitoring Wells

D 4-13 and D 4-14

4000

4050

4100

4150

4200

4250

4300

4350

4400

4450

4500

Jun-12 Sep-12 Dec-12 Mar-13 Jul-13 Oct-13 Jan-14 May-14 Aug-14

Pres

sure

, psi

a

Date

SECU D4-13/ D4-14 Pressure

D4-13 Top D4-13 Bottom D4-14 Bottom

D4-14 Top D4-13 Simulation D4-14 Simulation

D 4-14 Bot

D 4-13 Top

D 4-14 Simulation

D 4-13 Simulation

D 4-14 Top

D 4-13 Bot

Until end of August 2014

4000

4050

4100

4150

4200

4250

4300

4350

4400

4450

4500

Jun-12 Dec-12 Jul-13 Jan-14 Aug-14 Feb-15 Sep-15 Apr-16 Oct-16 May-17

Pre

ssu

re, p

sia

Date

SECU D4-13/ D4-14 Pressure

D4-13 Top D4-13 Bottom D4-14 Bottom

D4-14 Top D4-13 Simulation D4-14 Simulation

D 4-14 Simulation

D 4-13 Simulation

D 4-14 Bot

D 4-14 Top

D 4-13 Bot

D 4-13 Top

Until end of August 2017

41

CO2 Plume View Gas Saturation as of

September 1st, 2014

Note: grid refined

grid blocks are 80’ by 80’

D 9-7 D 9-8

12

00

fe

et

1200 feet

D_4_13 D_4_14

D_9_8GasInj1

286,000 287,000

286,000 287,000

38

7,5

00

38

7,7

00

38

7,9

00

38

8,1

00

38

8,3

00

38

8,5

00

38

8,7

00

38

8,9

00

38

9,1

00

38

7,7

00

38

7,9

00

38

8,1

00

38

8,3

00

38

8,5

00

38

8,7

00

38

8,9

00

38

9,1

00

38

9,3

00

0.00 255.00 510.00 feet

0.00 80.00 160.00 meters

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Scale: 1:3943Y/X: 1.00:1Axis Units: ft

0.05

0.13

0.20

0.28

0.35

0.43

0.50

0.58

0.65

0.73

0.80

SECARB Phase 3 - Plant BarryGas Saturation 2014-09-01 K layer: 10

42

CO2 Plume View Gas Saturation

as of December 31st, 2017

1200 feet

12

00

fe

et

D 9-7 D 9-8

D_4_13 D_4_14

D_9_8GasInj1

286,000 287,000

286,000 287,000

38

7,5

00

38

7,7

00

38

7,9

00

38

8,1

00

38

8,3

00

38

8,5

00

38

8,7

00

38

8,9

00

38

9,1

00

38

7,7

00

38

7,9

00

38

8,1

00

38

8,3

00

38

8,5

00

38

8,7

00

38

8,9

00

38

9,1

00

38

9,3

00

0.00 255.00 510.00 feet

0.00 80.00 160.00 meters

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0.05

0.13

0.20

0.28

0.35

0.43

0.50

0.58

0.65

0.73

0.80

SECARB Phase 3 - Plant BarryGas Saturation 2017-12-31 K layer: 10

43

Summary

We have a good capacity, injectivity, and no apparent

formation damage

The injected CO2 volume is accounted for

There is no evidence of CO2 at the off-set monitoring wells

MVA results indicate the CO2 is contained

Data, data, & more data

When deploying non-commercial MVA protocols, redundancy

with more commercial tools is necessary to ensure the data

quality

Every potential storage project is different & MVA should be

site specific in design

Regulators may add to a project’s MVA plan

44

(It’s a little known fact that the subsurface

geology is extremely favorable for long-

term underground storage of CO2!)

…but there was no existing regulatory

framework for our carbon capture

utilization and storage project?

How could Narnia begin to develop,

enact, and regulate such programs from

scratch?

That’s where the International Standards

Organization (ISO) comes in.

…but what if we were in Narnia?

45

What are Standards?

Consensus based

Designed as a rule, guideline

or definition

Revisable and updateable

Voluntary

Standards must fit to purpose:

– Prescriptive based

– Objectives based

– Performance based

– Principles based

– Hybrids

International Standards ISO

Why Standards?

Because they are not laws…

– Standards & regulations can work

together

Not Mandated

Typically initiated by industry…

– And therefore better received and

used by industry because they are

part of the process

Demonstrate regulatory

compliance

Streamline the regulatory process

Harmonize across jurisdictions

46

ISO Standards Development

• ISO does not write standards

• Technical Committees write standards

• P-Member countries approve standards

• Nations adopt ISO standards

• ISO does not influence the technical content

47

ISO Standards Process

48

ISO TC 265 – CCS Organization

Participants

Members

Twined Secretariat

Canada & China

Countries

P-Member Nations

O-Member Nations

Liaisons

NGOs & Liaisons

49

TC-265 Working Groups

TC-265

WG1

Capture

WG2

Transportation

WG3

Storage

WG4

Q&V (MVA)

WG5

Cross-Cutting

WG6

CO2-EOR

50

SECARB Expertise Globally

SECARB Members Richard Esposito, SoCo

Sue Hovorka, UT-BEG

George Koperna, ARI

Shahab Mohaghegh, WVU

Jack Pashin, GSA/OSU

Nino Ripepi, VT

Kimberly Sams Gray, SSEB

Greg Schnacke, Denbury

Mike Surface, Dominion

Steven Carpenter, ARI

~40% of expertise

RCSP Members Andrew Duguid

Jim Ekman

Sarah Forbes

Scott Frailey

Sallie Greenberg

Randall Locke

Sarah Wade

Mark Woods

SECARB + other RCSP

~75% of expertise

51

Thank You!

Washington, DC

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Arlington, VA 22203

Phone: (703) 528-8420

Fax: (703) 528-0439

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11931 Wickchester Lane

Suite 200

Houston, TX 77043-4574

Phone: (281) 558-6569

Fax: (281) 558-9202

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1282 Secretariat Court

Batavia, OH 45103

Phone: (513) 460-0360

Knoxville, TN

1202 Kenesaw Ave

Knoxville, TN 37919-7736

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