Transcript Using Saline Aquifers for Combined Power Plant Water Needs

1
Economic Uncertainty in Subsurface CO2 Storage:
Geological Injection Limits and Consequences for
Carbon Management Costs
Peter H. Kobos, Jesse D. Roach, Jason E. Heath,
Thomas A. Dewers, Sean A. McKenna, Geoff T. Klise,
Jim Krumhansl, David J. Borns, Karen A. Gutierrez
Sandia National Laboratories
and
Andrea McNemar
National Energy Technology Laboratory
30th USAEE/IAEE North American Conference, October 9-12, 2011, Washington, DC
Acknowledgements: This work is developing under the funding and support of the National Energy Technology Laboratory.
Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation,
for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000. Working Results. SAND2011-7325C.
Water, Energy and
CO2 Sequestration (WECS) Model:
(4) H2O Treatment & Use
(1) CO2 Capture
(3) H2O
Extraction
(2) Formation
Assessment
& CO2 Storage
Geologic Saline Formation
2
3
Project Timeline & Goals
Timeline
2008
2009
2010
2011
2012
• Completed Phase I: Developed a Test Case Model (WECS)
• Completed Phase II: Additional TOUGH2 Analysis
• Completed Phase III: Developed a single power plant to
any saline formation sink in the U.S. systems calculator
• Phase IV & V:
• Expanding the role of uncertainty within the model
• Several order of magnitude variation in key geologic
parameter (permeability)
• Incorporating uncertainties into costs
Single Source (power plant) Multiple Sources
Single Sink (saline formation)
Multiple Sinks
WECS
WECSsim
4
WECSsim Modular Structure
• Plant type
• CO2 generated
Power
Plant
Module
Various NETL reports inform
the Power Plant and Carbon
Capture Modules
CO2 Capture
Module
• Base LCOE
• CO2 capture
& compression
costs
• Parasitic energy
• Water demand
change
NatCarb Database polygon
analysis, well data analysis,
and heterogeneous
formation characterization
inform the CO2
Sequestration Module
• Mass CO2 to be sequestered
• Treated cooling H2O
• Energy required for H2O
extraction and treatment
Power Cost
(Integrating
Module)
• Water
extraction
transport and
treatment
costs
Extracted
Water
Module
• CO2 transport &
sequestration costs NETL reports, publically
Geologic CO2
Sequestration
Module
available reports, and well
analysis inform the
Extracted Water and
Power Cost Modules
• Extracted H2O capacity
• Extracted H2O quality
5
Geological CO2 Storage Database Challenges
Coal Power Plant
Gas Power Plant
Well
Well selected on depth and
salinity criteria
325 down selected regions
original NatCarb Atlas data
6
Distribution of Geologic Porosity
7
Relative Frequency (%)
Injectivity equation: permeability sampled from 4 Rock Types
0.160
Gulf
Dirty
Coast
sandstone
0.120
0.080
0.040
Clean
sandstone
Carbonate
0.000
-4
-2
0
log10[k (mD)]
2
4
8
Uncertainty and the Well Injectivity Index
I
well injectivity index;
measure of the “ease” of
injecting CO2 into the
well
q
volumetric injection rate
q
I
P
ΔP the pressure gradient
I
4 k k r H
 


4
A
  2s 
  ln
2 

  1.781C A rw 

(Bryant and Lake, 2005)
Reservoir volume
Radial flow from the
well
9
WECSsim Results:
Permeability and Costs
Injection costs as a function of injection well permeabilities
14
12
Injection Cost [$/tonne]
Mixed
Clean sandstone
10
Dirty sandstone
8
Carbonate
Gulf Coast
6
4
2
(~40 wells)
0
0.1
1
10
100
Geometric mean permeability of suite of injection wells [mD] (log scale)
1000
10
WECSsim Results:
Injection Costs and Formation Types
Injection costs for geologic storage of 11 million tonnes CO2 per year
12
10
injection costs [$/tonne]
Mixed
Clean sandstone
8
Dirty sandstone
Carbonate
6
Gulf Coast
4
2
0
0%
10%
20%
30%
40%
50%
60%
70%
80%
% formations with injection costs less than or equal to a given value
90%
100%
WECSsim Results:
Injection Costs Relative to Total Costs
$60
$/tonne stored
$50
injection
costs
$40
Injection Cost
% Formations
$9 - $12
6%
$6 - $9
16%
$1 - $6
68 %
< $1
10 %
$30
$20
CO2
capture &
transport
Injection Costs Distribution
$10
$0
Total CCS Costs
11
WECSsim Results:
Similar Full Economic Analysis Underway
$
Avoided CO2 Emissions
Note: Illustrative Example at this time
12
Conclusions
13
Low CO2 injection rates results in higher costs
• Low injectivity requires more injection wells and
therefore higher costs
• Accurate Site Permeability Characterization is key
Importance of High Quality Saline Reservoirs
• High permeability reservoirs with low injection costs
(< $1/tonne) represent < ~10% of the 325 formations
• Scale-up challenge
Using a national-level systems approach
• The mix of reservoirs of different quality is a major
factor that will control ‘supply’ of CO2 storage
Ongoing and Future Work
CO2 injectivity-brine extractivity and heterogeneity
• i.e., “How do injection rates improve with brine
extraction?”
Spatial distribution of CO2 sources to sinks
• i.e., “Are the high quality sinks accessible to large
sources?”
National Level Supply Assessment
• i.e., “How much low-cost CO2 storage exists in the
U.S.?”
14
15
For Further Information:
Initial Framework Description
Kobos, P.H., Cappelle, M.A., Krumhansl, J.L., Dewers, T.A., McNemar,
A., Borns, D.J., 2011. Combing power plant water needs and carbon
dioxide storage using saline formations: Implications for carbon dioxide
and water management policies. International Journal of Greenhouse
Gas Control, 5, 899-910.
Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation,
for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000. Working Results.
16
Backup Slides: Assessing U.S. deep saline formations
Data and Analysis
NatCarb data & analysis
NatCarb well data
Product
1. NatCarb 2008 geospatial
database estimates
(publically available)
2. NatCarb partnerships
(direct communication)
Other publically
available data and
SNL studies
3. Parameter estimation
from well data
Expert opinion
4. Geologic classification
of polygons to reduce
computational costs
SNL and publically available data & analysis
WECSsim
interpretation
of U.S. deep
saline
formation
resource
17
Limited Saline Formation Data
18
Gulf coast outliers
Injection costs as a function of injection well permeabilities
14
Mixed
Clean sandstone
Dirty sandstone
Carbonate
Gulf Coast
Injection Cost [$/tonne]
12
10
8
Why do the Gulf Coast formations
lie above the carbonate formations?
6
4
2
(~40 wells)
0
0.1
1
10
100
Geometric mean permeability of suite of injection wells [mD] (log scale)
1000
19
Gulf coast outliers
Injection costs as a function of injection well permeabilities
14
Mixed
Clean sandstone
Dirty sandstone
Carbonate
Gulf Coast
Injection Cost [$/tonne]
12
10
Example of a Gulf Coast formation
(Orange, id#2) with a slightly higher
geometric mean permeability of wells
than a carbonate formation (Blue,
id#165), but substantially more
injection wells. Why?
8
6
The carbonate formations have a
wider spread which results in some
high permeability wells. These can
handle high flow and thus reduce the
number of wells needed.
4
2
(~40 wells)
0
0.1
1
10
100
Geometric mean permeability of suite of injection wells [mD] (log scale)
1000
20
Gulf coast outliers
Permeability vs Flowrate and Relative Distributions
Individual Well Flow Rate [MGD]
2.5
Flowrate [MGD]
Carbonate Distribution
2
Gulf Coast distribution
1.5
1
0.5
0
0.001
0.01
0.1
1
10
Well Average Permeability [mD]
100
21
Gulf coast outliers
Permeability vs Flowrate for Individual Wells
Injection costs as a function
of injection well permeabilities
2.5
14
Flow Rate [MGD]
Gulf Coast (id# 2 ): 62 wells, 6.77 mD geometric mean permeability
12
Injection Cost [$/tonne]
Carbonate (id# 165 ): 36 wells, 6.47 mD geometric mean permeability
10
8
Mixed
Clean sandstone
Dirty sandstone
Carbonate
Gulf Coast
2
1.5
1
0.5
0
0.01
6
0.1
1
10
Permeability [mD]
100
4
id#2
2
(~40 wells)
id#165
0
0.1
1
10
100
Geometric mean permeability of suite of injection wells [mD] (log scale)
1000