IEAGHG/NETL
Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
PROJECT INFORMATION FORM
1. PROJECT IDENTIFICATION
Project Number
Project Title
Performer
FC26-05NT42590
Southeast Regional Carbon Sequestration Partnership - Phase III
Southern States Energy Board
2. PROJECT POINT OF CONTACT INFORMATION
Name
Organization
Phone
E-mail Address
DOE / NETL PROJECT MANAGER
Bruce Brown
NETL
412-386-5534
Bruce.Brown@NETL.DOE.GOV
PRINCIPLE INVESTIGATOR
Ken Nemeth
Southern States Energy Board
770-242-7712
nemeth@sseb.org
3. FIELD TEST INFORMATION
Field Test Name
Location
Amount of CO2
Source of CO2
1.
2.
3.
4.
5.
SECARB Anthropogenic Test
Citronelle, Alabama
300,000 to 450,000 metric tonnes
Commercial CO2 captured at Plant Barry (Bucks, AL) and transported via pipeline
4. FIELD TEST PARTNERS (Primary Sponsors)
(to add additional team partners, press the tab key at the end of the last row)
Electric Power Research Institute (EPRI)
Southern Company
Alabama Power
Denbury Onshore LLC
Advanced Resources International (ARI)
5. PHASE III PROJECT COST
DOE Share
Non-DOE Share
Total Value
Expenditures as
of 11/30/2010
6. KEY PROJECT DATES
Dollars
Percent
$76,981,260
69.10%
$34,432,171
30.90%
$111,413,431
$43,418,817
Baseline Completed
Drilling Operations Begin
Injection Operations Begin
MVA Events
6/2011
12/2010
7/2011
3/2011-10/2017
Injection Operations End
7/2014
7. BUDGET PERIODS
(to add additional budget periods, press the tab key at the end of the last row)
Period Number
Start Date
End Date
Cost
3 (FY08)
4 (FY09-FY14)
5 (FY15-FY17)
10/1/2007
1/1/2009
10/1/2014
12/31/2008
9/30/2014
9/30/2017
Page 1 of 15
$12,856,098
$87,625,019
$10,932,314
IEAGHG/NETL
Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
8. PRIMARY PROJECT GOAL
The two Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III projects share a
common goal of safely demonstrating large-scale, long-term CO2 injection and storage in a saline
reservoir that holds significant promise for future development within the SECARB region. The program
includes two field projects, the Early Test and the Anthropogenic Test; the continued characterization of
regional sequestration opportunities; and a preliminary evaluation of offshore transportation and storage
of CO2.
9. RESEARCH OBJECTIVES
In the Anthropogenic Test, the research and development objectives are to:
1) evaluate how to integrate and minimize the impacts of power plant CO2 capture on the transportation,
injection and long-term geologic storage operations;
2) evaluate injection and storage conditions in a regionally extensive saline reservoir in the Gulf Coast to
help establish regional CO2 injectivity and storage capacity;
3) understand how the saline reservoir’s internal architecture (the interplay between the reservoir flow
units, seals and baffles) can be used to maximize optimize storage and to minimize the areal extent of
the plume;
4) building on the “lessons learned” at the SECARB Phase III Early Test, apply commercially available,
low-risk “off-the-shelf” oilfield technologies for longer-term CO2 storage and plume tracking; and
5) evaluate the effect of subsurface migration and trapping of anthropogenic CO2 captured at a coal-fired
power plant on the geochemistry of saline reservoirs.
10. SUMMARY OF FIELD TEST SITE AND OPERATIONS
1. Geology, target formations, and known seals that will contain the CO2.
The project test site is located within the Citronelle oilfield, which lies in northern Mobile County,
Alabama (Figure 1). The oilfield lies at the crest of the of the Citronelle Dome geologic structure. The
Citronelle Dome has an ideal geometry for containment of CO2. The dome is a subtle, anticlinal structure
that contains a broad salt pillow at the core and provides four-way closure. The injection will take place
on the southeastern flank of the Dome within the Paluxy saline reservoir that overlies the primary oil
production horizon.
The injection target for the Anthropogenic Test is the Cretaceous-age Paluxy Formation. The Paluxy is a
350 meter thick package of sand, silt and shale strata, which occurs at a depth of about 3,000 meters at the
project test site. The properties of the Paluxy Formation are detailed in #3 below.
The primary confining zone, the basal shale of the Washita-Fredericksburg Formation, overlies and is
contiguous with the Paluxy throughout the Citronelle area and appears to possess the appropriate criteria
(lateral continuity, low permeability) to act as an effective CO2 seal. In addition to the basal WashitaFredericksburg shale, secondary overlying confining units including the Middle (Marine) Tuscaloosa
Formation, the Selma Group, and the Midway Shale, occur stratigraphically between the injection zone
and the base of the lowermost underground source of drinking water (USDW). As such, a vertical interval
of over 2,440 meters with numerous low permeability barriers occurs between the proposed injection
zone and the base of the lowermost USDW (Figure 3).
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March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
2. Based on seismic surveys, consideration of potential leakage points such as faults, fractures, and
existing borehole penetrations.
No significant faulting or fracture zones have been identified in the vicinity of the injection test (Figure
2) based on the 2-dimensional (2D) seismic surveys performed across the Citronelle Dome structure. As
such, the potential leakage conduits in the area are existing borehole penetrations. There are currently
approximately 420 deeper producing oil wells in the oilfield. However, preliminary reservoir simulations
of the CO2 injection suggest that the CO2 plume will be essentially radial in shape and the plume and area
of elevated pressure will extend less than 320 meters in any direction horizontally from the injection well
(Figure 4), intersecting only a very small number of existing wells.
A survey of existing wellbores within the injection footprint (also known as the “area of review”) showed
that all wells within the area are either active oilfield wells that undergo routing mechanical integrity
testing or have been properly plugged and abandoned per Alabama state regulations.
3. Physical information.
The porous and permeable sands of the Paluxy Formation represent a favorable injection reservoir in
terms of their areal extent and petrophysical characteristics. There is approximately 145 meters of net
sand in the Paluxy Formation, which occurs in over 20 sand units that range in thickness from 3 to about
25 meters in thickness. The Paluxy appears to contain a mix of continental, fluvial and marginal marine
deposits and relationships between sand units within the formation are complex. A detailed mapping and
petrophysical assessment of the Paluxy Formation at the test site was conducted by the Study Team. This
work suggests that average sand porosity is 19% and average permeability is 90 millidarcies. Several of
the Paluxy sand units appear to be laterally extensive. These units will be the injection targets for this test.
Detailed geologic data will be collected to confirm these qualities at the test site from characterization
wells drilled in advance of injection well drilling operations since existing well penetrations in the
oilfield, drilled on 0.16 square kilometer (40 acre) spacing, confirm the presence and extent of the
reservoir.
At the injection site, subsurface geologic strata, including the proposed injection and confining zones, dip
to the east-south-east at about 1.25 degrees. Buoyant CO2 is expected to migrate up dip towards the crest
of the dome, where it will be contained within the structure of the dome.
4. Surface location.
The proposed CO2 injection site is located approximately 3 miles southeast of the City of Citronelle,
Alabama. The test site is located in the Southern Pine Hills physiographic district, which is regionally an
irregular, relatively flat plain, covered by a mosaic of cropland, pasture, forest, and wetland. The
Citronelle oilfield is located in an upland area which contains notable elevation relief compared to the
district in general, with elevations ranging from 113 meters above mean sea level (msl) along hilltops to
about 30 meters above msl along streambeds. The topography in the study area is characterized by low
rounded hills and meandering low-gradient streams surrounded by wetlands. (Figure 5).
5. Injection operation.
The CO2 for the test is from a newly constructed demonstration-scale, post-combustion CO2 capture
facility at Alabama Power's existing 2,657 MW Barry Electric Generating Plant. A small amount of flue
gas from Plant Barry (equivalent to the amount produced when generating 25 MW of electricity) will be
diverted from the plant and captured using a process developed by Mitsubishi Heavy Industries to
produce highly pure CO2. Plant Barry is a coal-fired power plant located in Mobile County Alabama,
(Alabama Power is a subsidiary of Southern Company). The captured CO2 will be compressed at Plant
Barry and transported approximately 15 km by pipeline to the injection location at Citronelle.
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March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
Three new wells will be drilled during the test—a reservoir characterization well, a
characterization/observation/backup injection well, and a dedicated CO2 injection well. Drilling
operations on the characterization well began in December 2010. In addition to the new wells, the project
will utilize several existing oilfield wells surrounding the CO2 injection site to monitor injection
operations and to ensure public safety.
Beginning in the summer of 2011, between 100,000 and 150,000 metric tons per year of CO2 captured
from the pilot facility at Plant Barry will be transported to the storage site. CO2 injection will continue for
a period of three years. During the injection period, multiple CO2 monitoring technologies will be
deployed to track the CO2 plume, to measure the pressure front, to understand CO2 trapping mechanisms
of the Paluxy saline formation, and to monitor for leakage. Three years of post-injection monitoring are
planned. Site closure is expected to occur in 2017. The wells will either be plugged and abandoned per
state regulations or re-permitted for CO2-enhanced oil recovery operations into a deeper formation.
6. Target Formation Characterization.
The existence of available geophysical well logs from the Citronelle oilfield wells provided a wealth of
geophysical information on the Paluxy Formation and its overlying confining units. Wells were drilled at
a spacing of 0.16 square kilometers (40 acres) in the oilfield, providing a high-density characterization
data set. An area of approximately 54 square kilometers (about 340 acres) was characterized in detail
using existing well logs from oil production wells. Detailed correlations and mapping of Paluxy
Formation sand layers was conducted, providing a robust geological model of the likely target sands for
CO2 storage (Figure 6). However, due to the type (spontaneous potential/induction) and vintage of most
of the available well logs (1950’s), as well as the lack of local core data, there is very little information on
the porosity and permeability of the individual sand units within the Paluxy. As such, the porosity and
permeability used in the initial geologic model were estimated using regional log-core relationships. Data
acquired from core and high-resolution geophysical tools at the first characterization well (D-9-8 #2) will
be critical for providing detailed reservoir characterization information.
In addition to available oilfield log data, vintage 2-D seismic lines were available for subsurface structural
mapping. Assessment of two existing seismic lines showed that the Paluxy Formation and its overlying
confining units are continuous in the Citronelle Dome area.
7. Figures.
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IEAGHG/NETL
Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
Figure 1. Geographic Location of the SECARB Phase III Anthropogenic Test Site.
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March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
proposed injection area
proposed injection area
Figure 2. Structural Cross Section Showing the Geometry of the Anthropogenic Test Site and Surrounding
Area.
Page 6 of 15
Base of USDW
Figure 3. Stratigraphic Column of the Citronelle Dome Area.
Page 7 of 15
Protected
water
IEAGHG/NETL
Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
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Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
285,000
286,000
286,000
287,000
287,000
288,000
288,000
289,000
File: Citronelle_new_geol2.irf
File: Citronelle_new_geol2.irf
User: computation7
User: computation7
289,000
Date: 7/9/2010
Date: 7/9/2010
Scale: 1:8500
Scale: 1:8500
Y/X: 1.00:1
Y/X: 1.00:1
Axis Units: ft
Axis Units: ft
390,000
285,000
390,000
Gas Saturation
2024-01-01
K layer: 10
Gas Saturation
2014-01-01
K layer: 10
1.00
389,000
389,000
389,000
389,000
Mobile CO2
Saturation
0.91
0.81
1,867 feet
388,000
GasInj1
388,000
388,000
388,000
GasInj1
0.72
0.63
0.54
0.44
1,867 feet
387,000
387,000
387,000
387,000
0.35
0.26
0.17
285,000
285,000
286,000
286,000
287,000
287,000
288,000
288,000
289,000
0.08
289,000
Figure 4. CO2 Plume Extension at the End of the CO 2 Injection.
Figure 5. Topographic Map of the Anthropogenic Test Site (Contour Interval = 10 ft).
Page 8 of 15
1.00
0.91
0.81
0.72
0.63
0.54
0.44
0.35
0.26
0.17
0.08
IEAGHG/NETL
Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
Figure 6. Three-Dimensional View of the Geologic Model Showing the Paluxy Sand Layers.
11. SUMMARY OF MODELING AND MVA EFFORTS
Modeling Efforts. Computer Modeling Group’s (CMG) GEM-GHG reservoir flow simulator was
employed to model the subsurface injection of CO2 into the proposed injection zone. GEM-GHG is a
robust, equation-of-state, fully compositional reservoir simulator for modeling the flow of three-phase,
multi-component fluids. Further, it includes the capability of modeling CO2 (and other gases) injection in
parallel with comprehensive CO2 trapping, including residual gas trapping via relative permeability
hysteresis, CO2 dissolution in the aqueous phase and intra-aqueous reactions, mineral dissolution and
precipitation.
Using the detailed geologic model constructed as part of the characterization effort (Figure 6) and
assumptions of trapping mechanisms taken primarily from the Phase II Mississippi Test Site results, an
initial reservoir simulation was assembled. Injection of CO2 for three years at the maximum output from
the CO2 source (500 metric tons per day) was simulated for three years as well as 20 years of postinjection flow to understand the movement of the plume both under injection operations and under
equilibrium flow conditions. The goal of this initial simulation was to determine whether the Paluxy
Formation can serve as an adequate injection target capable of accepting the injection volume with only
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Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
moderate pressure buildup. Additionally, the results of the model served to delineate the project’s area of
review within which the condition of all existing well penetrations was assessed (see section #2). From
this initial injection simulation, several key findings can be made:
1. The plume is essentially radial during the injection period (Figure 4).
2. The dip of the Paluxy Formation influences the migration of mobile CO2 to a small degree after
injection operations cease. However, the low angle of dip (1.25 degrees) results in little postinjection updip migration.
3. The maximum movement of the CO2 is less than 320 meters in any direction (Figure 4).
4. The high transmissivity of the Paluxy results in a CO2 plume extent that is greater than the extent
of significant pressure buildup (greater than 5 percent of the native reservoir pressure).
5. Injection into multiple sand layers results in a plume of limited areal extent (approximately 63
acres ten years after injection operations have ceased).
Measurement Technologies Employed at Field Test Site. The MVA strategy at the Anthropogenic Test is
designed to test commercial “off-the-shelf” technologies to better understand their performance and future
application as listed in the table below.
Measurement Technique
Measurement Parameters
Application
Bottom-hole pressure
Pressure transducers on wireline with
real-time readout
CO2 saturation
Key measurement for assessing the reservoir’s pressure field.
Time-lapse crosswell seismic
imaging and vertical seismic
profiling (wellbore deployed)
Above-zone pressure and fluid
monitoring
Change from baseline sonic velocity
and amplitude
Distribution of CO2 plume vertically and horizontally.
Assess leakage signal (possible
through well completions- poor cement
bond)
Updip monitoring for CO2 buildup.
Tracers introduced in the CO2
stream
Measure tracer levels around existing
oilfield wells
Monitor for the presence of tracer buildup near new and
existing wellbores which would suggest leakage of CO2 along
the well annuli.
Drinking water aquifer
monitoring
Alkalinity, DIC, DOC, isotopes, chloride
selected cations and anions.
Monitoring of area freshwater aquifers for geochemical
changes related to shallow CO2 leakage.
Pulsed neutron reservoir
saturation;
CO2 saturation buildup near new and existing wellbores.
12. ACCOMPLISHMENTS AND MILESTONES TO DATE
 A major geologic characterization effort was conducted on the injection reservoir and confining units





using existing well data. Detailed maps of the Paluxy Reservoir sand units and multiple overlying
confining units were created.
The Environmental Impact Statement prepared by the project to fulfill the requirements of the
National Environmental Protection Act resulted in a Finding of No Significant Impact.
The project team has begun securing minerals and surface rights for the CO2 storage test
The Underground Injection Control permit application was submitted to the Alabama Department of
Environmental Management in December 2010.
Drilling activities for the project’s first characterization/observation well began in December 2010.
Reservoir data gathered from this well will be used to refine the geologic model.
Currently documenting the Test Site risk assessment and mitigation strategies.
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March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
13. SUMMARIZE TEST SINK STORAGE OPPORTUNITIES AND BENEFITS TO THE
REGION
Gulf Coast Cretaceous-age formations are key components of a larger, regional group of similar
formations, in terms of deposition and character, called the Gulf Coast Wedge. The wedge of sediments
spans the entire SECARB region and includes the largest capacity saline sinks in the United States. CO2
storage capacity estimates for the SECARB Gulf Coast Wedge range from 850 to 11,700 billion metric
gigatons (Gt) (Table 2). In comparison, annual stationary point-source emissions of CO2 for the region
have been estimated to be 1.085 Gt. Using the range of reported CO2 storage capacities, the saline
formations in the Gulf Coast Wedge may have the capacity to accommodate these emissions for over 800
years.
Table 2. CO2 Storage Capacity of the SECARB Region’s Gulf Coast Wedge Deep Saline Formations
(Source: Modified from 2010 Carbon Sequestration Atlas of the United States and Canada, NETL, November 2010)
CO2 Storage Capacity
Saline Formations
Gulf Coast Basins (Pliocene)
Gulf Coast Basins (Miocene)
Gulf Coast Basins (Oligocene)
Gulf Coast Basins (Eocene)
Gulf Coast Basins (Tertiary
Undivided)
Gulf Coast Basins (Olmos)
Tuscaloosa Group
Woodbine and Paluxy Formations
TOTAL
* Including offshore Federal
** Eastern Texas, TRRC Districts 1-6
Trillion Cubic Feet
Low
High
Estimate
Estimate
State
Multiple
States*
Multiple
States*
Multiple
States*
Multiple States
Billion Metric Tons
Low
High
Estimate
Estimate
2,571
35,345
136
1,870
7,582
104,173
401
5,512
2,488
34,215
132
1,810
2,959
40,684
157
2,153
Multiple States
323
4,435
17
235
TX**
8
116
0.4
6
Multiple States
103
1,412
5
75
TX**
96
1,324
5
70
16,130
221,704
853
11,731
14. FIELD TEST SCHEDULE AND KEY DECISION POINTS
(Paste Gantt Chart into the space below)
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Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
15. COST TARGETS AND/OR BRIEF ECONOMIC ANALYSIS
The SECARB Phase III Anthropogenic Test contains four major components, well drilling, CO2
transportation, CO2 capture, and MVA. While it is not a primary goal of this test to provide a true
economic assessment of CCS costs, some of the outcomes of the test may inform future cost analyses.
Potential outcomes of the four components related to CCS costs are listed below:
1) Well Drilling and Injection Equipment. A CO2-enhanced oil recovery (CO2-EOR) operator, Denbury
Onshore, LLC, has been contracted to drill the three project wells, purchase the injection surface
equipment, and operate the injection. An initial cost assessment of these components suggests that they
are in-line with CO2-EOR costs for CO2 injection. If this assessment remains accurate, it appears that well
drilling and CO2 injection costs may be estimated using established CO2-EOR cost models.
As part of this effort, two additional but important activities included securing some mineral and surface
rights in the area of the test and Underground Injection Control permitting activities for the test will add
to the CO2 storage knowledge base. When completed, the procedures and costs associated with these
activities may provide expectations for similar activities conducted elsewhere.
2) CO2 Transportation. Denbury Onshore, LLC has been contracted to construct and operate the 15
kilometer pipeline that will transport CO2 from the capture facility at Plant Barry to the injection test site.
While still early in the construction process, the costs estimates for construction and operations of this
pilot-scale, 10 cm (4 inch) pipeline are in line with CO2 pipeline capital and operational costs, indicating
commercial scale CO2 transportation pipeline costs are a good proxy for commercial scale CO2 storage
projects.
3) CO2 Capture. CO2 capture is expected to be the most costly component of CCS, varying widely based
on the technology deployed, source type and age, and CO2 quality. The capture technology being
deployed at the Anthropogenic Test is a technology developed by Mitsubishi Heavy Industries (MHI).
The results of the capture test, while proprietary, will help MHI Southern Company and EPRI in
assessing the potential for both scale-up of the technology and cost reductions.
4) MVA. The MVA strategy at the Anthropogenic Test is designed to test commercial “off-the-shelf”
technologies developed in the CO2-EOR industry for CO2 storage monitoring. If successful, the outcomes
of the test well help demonstrate that cost-effective, mature technologies exist today for CO2 monitoring,
their applicability as well as recommendations for timing and deployment, all of which are factors for
determining the costs associated with MVA activities.
16. POTENTIAL PROJECT RISKS
During the process of selecting and qualifying the specific Anthropogenic Test injection site, a series of
risk management actions were implemented to evaluate and mitigate the potential risk of CO2 leakage
from the target geological formations. To address these issues, the following five steps to leak prevention
and mitigation were proposed:
A. Carefully selecting favorable storage sites with low risks for CO 2 leakage. The pilot project has
purposefully selected a deep, saline reservoir that contains multiple, low permeability, thick seals
above the injection target (Paluxy Formation). These seals will act in tandem to ensure security of the
plume. To ensure the quality of the cap rocks, available well logs will be reviewed and seismic
methods will be employed to determine their continuity and identify potential breaks or thinning of
the seals. Finally, core and new geophysical log data will be collected from newly drilled wells to
assess the characteristics of the storage intervals and seals. Despite lying above a heavily drilled
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Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
oilfield, existing well completions were reviewed as well as temporary and permanent abandonment
procedures to mitigate the risks of leakage via existing deeper well penetrations. The MVA plan will
continue to re-look at the existing wellbores in the project area.
B. Putting high priority and emphasis on ensuring well integrity. The project team identified three
key priorities for ensuring long-term well integrity at a CO2 storage site: (a) identifying abandoned
wells in the vicinity of the proposed CO2 storage site and evaluating the need to replug, (b) designing
and installing the CO2 injection wells so that they will resist the loss of cement integrity and corrosion
of casing from the acidic CO2 and water mixture and, (c) properly designing the closure of the CO2
storage site, including plugging all CO2 injection and observation wells to promote long-term storage
integrity.
C. Conducting a phased series of reservoir simulations to predict CO2 plume migration. Based on
experiences to date, the project will use reservoir simulation throughout the project to predict the
movement of the CO2 in the subsurface. This can be subdivided into three stages in order to support
plume tracking, prevention and remediation efforts for this CO2 storage pilot. The first stage will
establish the injectivity and storage capacity of the site, as well as to project the anticipated movement
and location of the CO2 plume (see Section 8).
The second stage of reservoir simulation modeling will be undertaken as new data is collected from
characterization, injection or MVA activities. The nature and extent of any shale breaks that might
serve as baffles for promoting increased CO2 contact with the reservoir and how they influence CO2
migration will be monitored closely in order to achieve a quality final stage model. Newly collected
data on relative permeability will be modeled to better estimate CO2 injectivity and the pore-space
(capillary) trapping.
The third and final stage of reservoir simulation will be used to project the long-term (1,000 year)
trapping, immobilization and fate of the CO2 plume.
D. Installing and maintaining a comprehensive monitoring system for the CO2 storage site. The
subsurface CO2 monitoring system will need to serve as an “early warning system” of any impending
CO2. These tools are listed in Section 8.
E. Establishing a “ready-to-use” contingency plan and strategy for remediation. The project team
is compiling a contingency plan outlining best practices and available options should a leak occur.
17. KEY FINDINGS FROM PHASE II AND THEIR SIGNIFICANCE
The Phase II Mississippi Test Site CO2 injection at Plant Daniel was conducted in 2008. The project
included the drilling of two deep wells (3,100 meters) on the Plant’s property, injecting 3,000 metric
tons of CO2, and monitoring of the plume in the subsurface and for leakage at the ground surface. Key
findings from this test include:
1)
2)
The CO2 injection pilot at Plant Daniel demonstrated that conventional oilfield injection well
design, drilling and completion methodologies can be easily adapted for use in CO2 injection well
drilling.
Neither of the deep monitoring methods (vertical seismic profiling and cased-hole neutron
logging) were able to track the CO2 plume, highlighting the difficulty of tracking a small CO2
plume in the deep subsurface.
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3)
The use of high-resolution reservoir characterization tools beyond conventional wireline and
coring tools, as well as advanced reservoir simulations for accurate plume prediction will be
essential for designing a successful monitoring program. The early gathering of detailed
characterization data will be critical in predicting the short-term migration paths of a CO2 plume,
and the long-term mechanisms of CO2 immobilization, using a series of reservoir simulations.
18. ADDITIONAL PROJECT INFORMATION
19. BIBLIOGRAPHY (PHASE I, II, AND III)
(Bold Items are Peer Reviewed)
Following are selected papers and other relevant materials published by the SECARB team.
Esposito, R.A., and Tinsley, R.J., Monitoring Protocol Design for a Carbon Dioxide Flood in Coal Seams
in the Black Warrior Basin in Alabama, Proceedings of the 2006 International Coalbed Methane
Symposium.
Esposito, R., Rhudy, R., Trautz, R., Koperna, G., and Hill, J. Integrating Carbon Capture with
Transportation and Storage. GHGT-10 Proceedings, 2010.
Koperna, G., Riestenberg, D., Kuuskraa, V., and Esposito, R., “The Importance of Reservoir Architecture
in Encouraging Plume Immobilization and Enhancing Storage Capacity,” presented at the 6th
Annual Conference on Carbon Capture and Storage, 7-10 May, 2007, Pittsburgh, PA.
Koperna, G., Riestenberg, D., Petrusak, R., Esposito, R., and Rhudy, R. Lessons Learned while
Conducting Drilling and CO2 Injection Operations at the Victor J. Daniel Power Plant in
Mississippi. SPE 124003. 2009 SPE Annual Technical Conference, October 4-7, 2009.
Kuuskraa, V.A., “Maximizing Oil Recovery Efficiency And Sequestration Of CO2 With “Game Changer”
CO2-EOR Technology”, Lecture Series, Sponsored by the Society of Petroleum Engineers (SPE),
Distinguished Lecturer 2007-2008 season.
Kuuskraa, V.A., Koperna, G.A., and Schepers, K., CO2 Storage Engineering: Real Solutions to Real
Problems, SPE 139512, prepared for presentation at the SPE International Conference on CO2
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IEAGHG/NETL
Regional Carbon Sequestration Partnerships Expert Review
March 14-17, 2011
Southeast Regional Carbon Sequestration Partnership Phase III Anthropogenic Test
19. BIBLIOGRAPHY (PHASE I, II, AND III)
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