Arizona Utilities
CO2 Storage Pilot
Regional Carbon Sequestration
Partnerships Initiative Review Meeting
Pittsburgh, Pennsylvania
October 7, 2008
John Henry Beyer, Ph.D.
WESTCARB Program Manager, Geophysicist
510-486-7954, jhbeyer@lbl.gov
Lawrence Berkeley National Laboratory
Earth Sciences Division, MS 90-1116
Berkeley, CA 94720
WESTCARB region has major CO2 point sources
2
WESTCARB region has many deep saline
formations – candidates for CO2 storage
WESTCARB also created GIS layers
for oil/gas fields and deep coal basins
Source: DOE Carbon Sequestration
Atlas of the United States and Canada
3
Arizona Utilities CO2 Storage Pilot
Contracting and Funding Flow
Department of Energy Arizona Electric Power Cooperative
National Energy Technology Arizona Public Service Company
Laboratory Salt River Project
Tucson Electric Power
Lawrence Lawrence National Rural Electric Cooperative
California Energy
Berkeley National Livermore National Peabody Energy
Commission
Laboratory Laboratory
California Institute for Electric Power
Energy & Environment Research Institute
(UCOP)
– Aspen Environmental – Sandia Technologies, LLC
– Bevilacqua-Knight, Inc. – Errol L. Montgomery & Assoc.
– Schlumberger Carbon Services
– Drilling Contractor
– CO2 Supply
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Arizona Utilities
CO2 Storage Pilot
project partners
Arizona Public Service Company
Salt River Project
Tucson Electric Power
Arizona Electric Power Cooperative
National Rural Electric Cooperative Association
Peabody Energy
Electric Power Research Institute
Lawrence Berkeley National Laboratory
Lawrence Livermore National Laboratory
California Energy Commission
U.S. Department of Energy
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EPRI - Site Selection and Project Support
Storage potential of Arizona
geologic provinces
Significant capacity in
Colorado Plateau Province
Limited capacity in Basin and
Range Province
Minor capacity in Central
Highlands Province
6
Project Site at Arizona Public Service Company
Power Plant between Holbrook and Joseph City
Colorado Plateau location is
scientifically interesting and has
large CO2 storage potential
Potential high salinity,
carbonate reservoir formation
Thick, low permeability cap rock
Cooperative project partner that
owns surface and subsurface
rights
Near major highway, power line
Controlled access to drill site
7
Geologic section in southern Colorado Plateau
Vertical exaggeration 50:1
8
Exploratory well to confirm suitability of site
Geology at Project Site
Arizona Utilities CO2 Storage Pilot Injection Well Land Surface 5,100 Feet ASL
Proposed Completion Well Schematic
Silty Sandstone/
0
GROUND LEVEL
All depths reference Rig Kelly Bushing Moenkopi Formation Gypsum
1
Moenkopi from Surface Rig Kelly Bushing = 15’ above Ground Level 340
Ground Level ~ 5,120’
Top of Coconino +/- 225 ft Coconino Sandstone Sandstone
COMPLETION DETAILS
Fine
740
2 1. Conductor Casing: 13-3/8-inch, 48 pounds per foot, Schnebly Hill Formation Sandstone 1,000
Base of Coconino
+/- 625 ft
surface to +/-40 feet, grouted to surface
2. Surface Casing: 9-5/8-inch, 36-pounds per foot. J-55,
1,040
ST&C, Set from surface to +/-965 feet in a 12-1/4-inch
1,000 Base of Schnebly Hill hole. Cemented with Lead Slurry of 300 sacks of
“Lightweight” cement mixed at ~12.3 pounds per gallon
Siltstone
+/-925 ft
and Tail Slurry of Class “G” cement mixed at ~15.6
pounds per gallon.
Mudstone
3. Protection Casing: 5-1/2-inch 15.50 pounds per foot, J- Halite
55, LT&C. Set from surface to 4,000 feet in a 8-1/2-inch
hole. Cemented with Lead Slurry of 380 sacks of
Supai Formation
“Lightweight” Cement mixed at ~11.5 pounds per gallon
and 120 sacks of 50-50 Pozmix cement mixed at 13.5
Limestone Marker Bed 1,865
pounds per gallon. Note: The final design may include a
two stage cementing program and different cement
slurries. 1,885 2,000
3
4. Stage Tool. Will only be used if a two-stage cementing
Supai Formation Siltstone
2,000 program is required.
4
5. Injection Tubing: 2-7/8-inch, 6.5 pounds per foot, J-55, Mudstone
EUE 8rd. Surface to +/- 3,325 feet
6. Downhole completion consisting of: TAM Inflatable
Packer (set at 3,460 feet) and inflate line, w/pass through
with minor
2,525
sub on top of packer; Downhole Pressure & Temperature
Gauge and LBL Stainless Steel U-Tube Sampler below
packer. Sandstone/Dolomite
5
7. Production Perforations: Martin Fm Test Interval: 3,460
feet to 3,660 feet w/ 4 shots per foot, 90 degree phasing. 3,000
3,000
8. Planned Total Depth; +/-4,000 feet
Mudstone 3,075
Notes Naco Formation Limestone
Top of Naco Fm
The Martin Formation is the Primary Target and Sandstone
+/-2,960 ft
the Naco is the Secondary Target
Dolomite 3,575
Top of Martin Fm +/-3,460 ft
The Supai is expected to contain halite beds
below +/-1,200 feet below ground Martin Formation Mudstone 3,775
Sandia
Siltstone
7
6
Technologies, LLC
4,000
6731Theall Road, Houston, TX 77066
4,000 8 Tel: (832) 286-0471 Fax: (832) 286-0477
Drawn by: djc Date: May 2008 Drawing not to scale
Pre-Cambrian Granite
Pre-Cambrian
Basement at +/-3,660 ft Basement
Source: Sandia Technologies, LLC Source: Errol L. Montgomery & Associates
9
Evaluation of USDW above seal
Elevation and flow
TDS in Coconino
direction in
Sandstone (USDW)
Coconino Sandstone
Source: Errol L. Montgomery & Associates
10
Scientific Objectives
Determine injectivity and storage capacity of the
reservoir
Show that surface and borehole geophysical
techniques can monitor the trapping of the injected
CO2 in the subsurface
Assess and maintain caprock integrity
Demonstrate safe storage of CO2 in porous carbonate
formations containing non-potable saline water
beneath thick, low permeability seal
Develop, calibrate, and validate multiphase flow
models for CO2 injection into saline formations typical
of the Colorado Plateau in northeastern Arizona Cholla Power Plant
fly ash pond
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Test Plan
Numerical simulation of CO2 injection
Drill and log a single well ~4,000 feet (1,200 m) deep near the APS
Cholla Power Plant fly ash pond
Ensure TDS of reservoir formation >10,000 mg/L
Step-rate injection test to determine maximum safe injection pressure
Short huff-puff test with a few tons of CO2 to estimate residual saturation,
and test water-CO2 interaction (using tracers)
Inject 2,000 tons of commercial-grade CO2
Sample fluids and tracers with U-tube system; chemical analysis
Pre- and post-CO2 injection monitoring
– Reservoir Saturation Tool (RST) logs
– Distributed Thermal Perturbation Sensor (DTPS) logs
– Vertical seismic profile (VSP) surveys
Release pressure in well and flow back fluids (water, CO2, phase-
partitioning tracers); analyze interactions
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0
-400 Naco (L)
TOUGH2* simulation -200
Naco (U)
Z (ft)
-500
Martin
Z (ft)
of CO2 injection -400
Naco (L) -600
Injection
At end of injection
Jerome
-7000 200 400 600 800 1000
Martin
-600 X (ft)
Jerome
0 500 1000 1500 2000
Uniform high permeability 0
X (ft)
kh = kv = 100 mD Naco (U)
-200
Z (ft)
2,000 tonnes injected over 30 days (0.8 kg/s) -400
Naco (L) 1 mo. after end of injection
into Jerome Member of Martin Formation
Martin
-600
• Depth = 1,100 m (3,700 feet) Jerome
0 500 1000 1500 2000
Injection X (ft)
• P = 10.3 MPa (1,500 psi) [hydrostatic]
0
• T = 54°C (129°F) [normal gradient] Naco (U)
-200
• Porosity = 10%
Z (ft)
Naco (L) 3 mo. after end of injection
• Residual saturation, Sgr = 5% -400
SG Martin
-600
Jerome
0.50
0.45
Gas saturation 0 500 1000 1500 2000
Injection X (ft)
0.40 Fraction of
0.35 pore space 0
0.30 filled by Naco (U)
0.25 -200
supercritical CO2
Z (ft)
0.20
Naco (L)
0.15 -400 5 mo. after end of injection
0.10
0.05 Martin
* Transport Of Unsaturated -600
Jerome
0.00 Groundwater and Heat 0 500 1000 1500 2000
Injection X (ft)
0 100 200 300 400 500 600 700
meters
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0
TOUGH2 simulation -200
Naco (U)
-500
Naco (L)
Z (ft)
Martin
of CO2 injection
Z (ft)
-600
Naco (L) At end of injection
-400 Injection
Jerome
-7000 200 400 600
High horizontal permeability -600
Martin
Jerome
X (ft)
0 500 1000 1500 2000
Low vertical permeability X (ft)
0
Naco (L)
-500
Formation Thickness kh (mD) kv (mD) Naco (U)
-200
Z (ft)
Upper Naco 76 m (250 ft) 10 1 Martin
Z (ft)
-600
Lower Naco 76 m (250 ft) 100 3 Naco (L) 1 mo. after end of injection
-400 Injection
Jerome
Upper Martin 21 m (69 ft) 100 3 -7000 200 400 600
Jerome 40 m (131 ft) 700 20 -600
Martin
X (ft)
Jerome
0 500 1000 1500 2000
2,000 tonnes injected over 30 days (0.8 kg/s) X (ft)
into Jerome Member of Martin Formation 0
Naco (L)
-500
Depth = 1,100 m (3,700 feet) -200
Naco (U)
Z (ft)
Martin
Z (ft)
P = 10.3 MPa (1500 psi) [hydrostatic] -600 5 mo. after end of injection
Naco (L)
T = 54°C (129°F) [normal gradient] -400 Injection
Jerome
-7000
Porosity = 10% Martin 200 400 600
-600 X (ft)
Jerome
Hysteretic effects included:
0 500 1000 1500 2000
– Residual saturation for drainage, Sgr = 0% X (ft)
– Residual saturation for imbibition, Sgr = 25% 0
Naco (L)
SG -500
Naco (U)
0.50 -200
Z (ft)
0.45 Martin
Z (ft)
0.40 Gas saturation -600
0.35 Fraction of -400
Naco (L) 11 mo. after end of injection
Injection
0.30 Jerome
0.25 pore space -7000 200 400 600
0.20 Martin
0.15 filled by -600
Jerome
X (ft)
0.10
0.05
supercritical CO2 0 500 1000 1500 2000
0.00
X (ft)
0 100 200 300 400 500 600 700
meters
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TOUGH2 simulation of pressure during CO2
injection
Pressure in
reservoir formation at
injection depth
High horizontal permeability
Formation Thickness kh (mD) kv (mD)
Upper Naco 76 m (250 ft) 10 1
Lower Naco 76 m (250 ft) 100 3
Upper Martin 21 m (69 ft) 100 3
Jerome 40 m (131 ft) 700 20
Leading edge of CO2 plume
2,000 tonnes injected over 15 days (1.6 kg/s) 2.7% pressure
into Jerome Member of Martin Formation increase
• Depth = 1,100 m (3,700 feet)
• P = 10.4 MPa (1558 psi) [hydrostatic] Background hydrostatic pressure = 1558 psi
• T = 54°C (129°F) [normal gradient]
• Porosity = 10%
• Residual saturation for drainage, Sgr = 0%
0 25 50 75 100 125
meters
15
U-Tube System – continuous water, CO2, and
tracer samples at reservoir pressure
On-site
chemical
analysis
Pressurized
Packer sample
storage
Well
U-tube and check
valve strapped to
Frio Brine CO2 Pilot, Texas
production tubing
Source: Barry Freifeld, LBNL
16
Distributed Thermal Perturbation Sensor (DTPS)
for tracking CO2 migration in the subsurface
Thermal conductivity measurements
during and after CO2 injection to monitor
the distribution of CO2 near the well
The DTPS consists of a borehole-length electrical
resistance heater and fiber optic distributed
temperature sensor
Constant heating is applied along the borehole,
then is turned off. The temperature sensor
measures the decay
The low thermal conductivity of CO2 versus water
allows for estimates of CO2 saturation
The DTPS has been successfully tested at the
CO2SINK project in Germany
Source: Barry Freifeld, LBNL
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Permitting
DOE Environmental Questionnaire/NEPA –
Approved by DOE
US EPA Region 9, UIC permit application –
Submitted for Class V Experimental Well
Aquifer Protection Program permit, Arizona
Department of Environmental Quality –
Application submitted
Drilling permit, Arizona Oil & Gas Conservation
Commission – to be submitted
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ADEQ Aquifer Protection Program (APP) Permit
All aquifers are designated as Drinking Water Aquifers
Aquifer – a geologic unit with sufficient permeable to produce
5 gallons of water per day
Water quality is not specified in law or regulation (no TDS limit)
Use Best Available Demonstrated Control Technology (BADCT)
Point of Compliance is the location down-dip where water quality
returns to background level
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Proposed APP Permit Conditions
Point of Compliance: 400 ft (122 m) up dip from well
VSP
Model predictions form basis of
Point of Compliance (POC)
Injection
Well
Verification:
– Lateral POC determined
Base of fresh water
by VSP
– Vertical POC determined
by RST well logs
– Injection zone Vertical POC
monitoring of pressure
Confining layer
& temperature
Naco (L)
Injection Zone Martin
Well logs
Jerome Lateral POC
(400 ft, 122 m)
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Arizona Utilities CO2 Pilot Summary
WESTCARB has …
Completed a hydrogeologic study
Selected a site for the AZ pilot test
Added new industry partners
Characterized the hydrogeology
Modeled CO2 plume size and
formation pressure
Received NEPA approval from DOE
Submitted APP and UIC permit
applications
Engaged in public outreach to the
community through public meetings
…and will begin
Drilling and testing in January 2009
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