carbon dioxide capture and sequestration in saline ... · capillary pressure curve p cap (pa) brine...
TRANSCRIPT
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Professor Sally M. BensonEnergy Resources Engineering Department
Executive Director, Global Climate and Energy ProjectStanford University
Los Alamos, NM, June 30, 2008
Carbon Dioxide Capture and Sequestration in Saline Aquifers: Fundamental
Studies of Multi-Phase Flow of CO2 and Brine
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Topics
• Motivation and importance of CCS• Sequestration options• Rationale for a focus on saline aquifers• Key questions for saline aquifer
storage• Multi-phase flow investigations for CO2
and brine• Conclusions
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Gas, 19.70%
Oil, 39.50%
Coal, 40.50%
Other, 0.30%
CO2 Emissions from Fossil Fuels
Power, 10539
Cement, 932
Refineries, 798
Iron and Steel, 646 Other, 46260% of global
fossil fuel emissions come
from large stationary sources
CO2 Emissions (Mt/year)
40.5% of global emissions come from coal… this is not expected to change any
time soon.Global Emissions 27,136 Mt (2005)
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Carbon Dioxide Capture and Geologic Sequestration is a Way to Reduce Emissions
CaptureCapture UndergroundUndergroundInjectionInjection
PipelinePipelineTransportTransportCompressionCompression
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CCS Could Make a Large Contribution to Reducing CO2 Emissions
From IPCC, 2007:WG III
650 CO2-eq 550 CO2-eq 450 CO2-eq
0
5
10
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30
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1990
2010
2030
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2090
Emis
sion
s (G
tC-e
q)
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25
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1990
2010
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2090
Emis
sion
s (G
tC-e
q)0
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1970
1990
2010
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Emis
sion
s (G
tC-e
q)
Sinks
Non-CO2
Other
Fuel switch
CCS
Biofuels
Nuclear, renewable
Efficiency
Under a range of GHG stabilization scenarios – CCS is expected to contribute ~ 20% to emissions reductions
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Options for CO2 Sequestration
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Why Saline Aquifers?Widespread Global Distribution
Saline aquifers in sedimentary basins are widely distributed and co-located with many CO2 sources.
IPCC, 2005
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Why Saline Aquifers?Largest Capacity
~ 1041000Saline aquifers
2003–15Coal seams (ECBM)
900a675aOil and gas fields
Upper Estimate of Global Storage
Capacity (GtCO2)
Lower Estimate of Global Storage
Capacity (GtCO2)
Reservoir TypeFrom IPCC Special Report
a. Estimates would be 25% larger if undiscovered reserves were included.
Current U.S. Saline Aquifer Capacity Estimates (U.S. DOE)
920 to 3,380 Gt CO2
IPCC, 2005
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Some Key Questions for Saline Aquifer Storage
1. What kind of reservoir seals are needed to contain CO2?
2. What fraction of the pore space can be used for storage?
3. How far will the CO2 move from the injection site?4. What is the long term fate of CO2?5. Where does the displaced brine go?6. What is the risk that CO2 will leak out of the
storage reservoir?
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Multi-Phase Flow DynamicsKey to Answering Questions
GravityViscous and
capillary forces Heterogeneity Structure
Answering these questions depends on the complex interplay of viscous, capillary, buoyancy forces, heterogeneity and structure of the aquifer.
2.2 mm
Micro-tomogram of a CO2 and water-filled rock: From L. Tomutsa, LBNL
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Hierarchy of Space and Time ScalesPore-Scale
Core-Scale
Pilot-Scale
Field-Scale
Primary Focus of Our Current Research
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Core-Scale Experiments I
• Relative Permeability Measurements• Displacement Efficiency
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Relative Permeability CurvesR
elat
ive
Per
mea
bilit
y
Brine Saturation
CO2 Brine
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Early Experimental Results: Small-Scale CO2 Saturation Variations
5% CO2 10% CO2
20% CO2 50% CO2 80% CO2
90% CO2 100% CO2
CO2 Saturation:0% 100%50% 75%25%
Sub-corescale saturation variations generally overlooked in relative permeability measurements.
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Homogeneous Simulations
10%CO2
90%CO2
100%CO2
Variable Φ, k Simulations
CO2 Saturation:0% 70%
Simulated CO2 SaturationsConstant Pc Produces Homogeneous CO2 Saturations
PorosityLab Data
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Fitting Capillary Pressure CurveP
c (P
a)
Brine Saturation
1000
10,000
100,000
Simulation Input Curve*
*Silin et al. (submitted, 2
Hg Injection Data Curve
2000 8000Pcap (Pa)given 20% CO2
Pcap = 4500PaPcap =
4500Pa
Φiki√Pc,i ∝
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10%CO2
90%CO2
100%CO2
Variable Φ, k Simulations
CO2 Saturation:0% 70%
Lab Data
Simulated CO2 SaturationsVariable Pc Produces Small-scale CO2 Saturation Variations
Variable Pc Simulations
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Capillary Pressure CurveP
cap (P
A)
Brine Saturation
CO2 Saturation:
0% 70%10% CO210% CO290% CO290% CO2100% CO2100% CO2
Avg. Pc Φ=.22 k=301mD Pc Envelope
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CO
2 S
atur
atio
n
Length of Core (cm)
3.09.0
mL/min
0.3
0.065
0.03
0.001
Buckley-Leverett
0 87621 53 4
Flow-Rate Dependent Displacement Efficiency
Consequence of Variable Capillary Pressure
Simulated Displacement Efficiency
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Tantalizing Results
0
0.2
0.4
0.6
0.8
0.1 10 1000
Pore Volumes Injected
CO
2 Sat
urat
ion 0.22m/day 1.1m/day 5.5m/d 11m/day
16.5m/d
But the experiment was flawed.
Data from Liviu Tomuta, LBNL, 2006.
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Core-Scale Experiments II
• Relative Permeability Measurements• Displacement Efficiency• Flow Rate Dependence of Both of These
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Schematic of Multi-Phase Flow Apparatus
R R
R
D
A2 B1 B2 C
R
PR
A1T°= 5°C
T°res
T°res
T°room
T°roomCO
2ta
nk
RR R R
R
pressure transducer
relief valve
manual on/off valve
electric on/off valve
filter
check valve
separator
CO2 Brine
confiningpressurePres
3-way valve
backpressurePpore
core holder
CO2
brine
R R
R
D
A2 B1 B2 C
R
PR
A1T°= 5°C
T°res
T°res
T°room
T°roomCO
2ta
nk
RR R R
R
pressure transducer
relief valve
manual on/off valve
electric on/off valve
filter
check valve
separator
CO2 Brine
confiningpressurePres
3-way valve
backpressurePpore
core holder
CO2
brine
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Multi-Phase Flow Laboratory
Replicate in situ conditions- Pressure- Temperature- Brine composition
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● Sample = Berea Sandstone
q ΔPA
Lk
μ1=
known coefficient
A = 40.53 cm2
L = 15.24 cmμ = 0.54 cp
● Absolute permeability:- Injection of brine (10 000 ppm NaCl ≈ 10 g/L)
T°= 50°C , Ppore = 12.4 MPa
- Measure ΔP as a function of the Flow Rate q
kav= 430.3 ± 7.0 mD
Petrophysical Characterization: Absolute Permeability
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ΔPpr
essu
re d
rop
(psi
)
q Flow rate (mL/min)
15.24 cm
5.08
cm
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→ Using the CT scanner we take the● DRY images when the core is completely dry● BRINE SATURATED images when the core is full of brine
→ each slice is● 3 mm thick ● 169*169 pixels (pixel size = 0.3*0.3 mm)● gap of 2.08 mm between 2 consecutives images
3 mm
0.3 mm
1 voxel
Petro-physical Characterization:Porosity
147.32142.24
outlet
inlet0
5.0810.16
15.2420.32
25.430.48
35.56distance from the inlet (mm)
airbrine
drysatbrine
CTCTCTCT
−−
=Φ
26Permeability (mD)
Kozeny – Carman relation
2
3
1 )(Sk
φφ−
=
• Porosity and permeability have important spatial variations due to the pore-scale structure of the rock sample.
• Slice-averaged values are relatively constant along the core.
Petrophysical Characterization:Sub-Core Scale Property Variations
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● Co-injection of supercritical CO2 and brineat reservoir conditions:
T°= 50°CPpore = 12.4 MPa
Experimental Conditions
CO2CO2 saturated brine
Supercritical
μ = 0.046 cPd = 0.28 g/cm3
Liquid
μ = 0.558 cPρ = 0.990 g/cm3
Viscosity ratio μ brine / μ CO2 = 12.1
Density ratio ρbrine / ρCO2 = 3.5
Bond number ~ 2.2.10-3
Capillary number ~ [2.10-6 -10-5]
● Physical properties of CO2 and brineat reservoir conditions:
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Experimental Procedure
● At a given total Flow Rate :- the core is initially saturated with brine- CO2 and brine are injected at a given fractional flow
- wait until steady state is reached (8 to 10 pore volumes)stabilization of pressure drop and saturation
- measure ΔP, saturation
-increase the proportion of CO2 ( )
)brine(FR)CO(FR)CO(FRf
)brine(FR)CO(FR)brine(FRf
CO
brine
+=
+=
2
2
2
2
2COf
)brine(FR)CO(FR +2
● Run the same procedure at different total flow rates: 2.6, 1.2 and 0.5 mL/min
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0.88 2.06 3.38 5.29
0.315 0.387 0.3952COS 0.394
# porevolumes
Injection of 100% CO2 @ 2mL/minINLETOUTLET
CO2
The steady state is reachedafter ~ 5 pore volumes
To be sure to always reach steadystate ΔP and are measured afterhaving injected 8-10 pore volumes of fluid.
2COS●
●
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0CO2 saturation
CO
2sa
tura
tion
nb of pore volumes
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Saturation Maps: Total Flow Rate = 2.6 mL/min
0.25 0.33 0.50
0.60 0.72 1
2COf
0.060 0.152 0.205
0.273 0.341 0.430
2COS
2COf
2COS
INLETOUTLET
CO2
brine
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0CO2 saturation
top
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0.25 0.33 0.50
0.60 0.79 1
2COf
0.054 0.133 0.209
0.227 0.269 0.380
2COS
2COf
2COS
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0CO2 saturation
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Saturation Maps: Total Flow Rate = 1.2 mL/min
INLETOUTLET
CO2
brine
top
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0.16 0.30 0.42 0.60
0.84 1
2COf
0.019 0.045 0.177
0.233 0.244 0.271
2COS
2COf
2COS
0.74
0.105
Saturation Maps: Total Flow Rate = 0.5 mL/min
INLETOUTLET
CO2
brine
top
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Permeability (mD)
2.6
0.4302COS 0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0CO2 saturation
1.2
0.380
0.5
0.271
Flow rate(mL/min)
• High permeability paths correspond to high CO2 saturation close to inlet
• Elsewhere the correlation between permeability & saturation is poor due to unconnected high permeability pathways
• The low porosity regions act as local capillary barriers
INLETOUTLET
CO2
brine
Explanation for Saturation Variations
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The higher the proportion of CO2, the higher the CO2 saturation.
Lower values when the flow rate decreases.
●
●
2.6 mL/min 1.2 mL/min
0.5 mL/min
CO
2sa
tura
tion
Distance from INLET (cm)
CO
2sa
tura
tion
Distance from INLET (cm)
CO
2sa
tura
tion
Distance from INLET (cm)
CO2 Saturation Profiles at Different Fractional Flows
CO
2sa
tura
tion
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Flow Rate Dependent CO2 Saturations
At any given fractional flow the CO2 saturation is a function of the flow rate
The higher the flow rate, the higher the CO2saturation
Results not consistent with classical multi-phase flow theory where saturation – and thus relative permeability – are independent of flow rate
●
●
●
CO
2sa
tura
tion
Flow rate (mL/min)
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Flow Rate Dependent Relative Permeability Curves
• Same general trend
• Global shift between the two curves
• The lower the flow rate, the lower the relative permeability to brine and CO2
Brine saturation
Rel
ativ
e pe
rmea
bilit
y
End Point Saturations
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Flow Rate Dependant End-Point Brine Saturation
● Strong variations of the end point brine saturation
● Unusually high saturation end-point values
● Asymptotic value for high flow rates
Flow rate (mL/min)
End
poin
t brin
e sa
tura
tion
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Why Might This Be Important?
Rel
ativ
e pe
rmea
bilit
y
• Relative permeability curves (drainage) are typically treated as single-valued functions in numerical and analytical models– These data suggest this may not
be correct• Plume size and capacity depend
on relative permeability curves– These data suggest that plumes
will be bigger and capacity will be lower than estimates based on relative permeability measurements made at high flow rates
• Volume averaging will have a large effect on simulation results– Tendency to overestimate CO2
saturations
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Core-Scale Multiphase Flow Experiments
Multiphase Flow Theory
PetrophysicalCharacterization
NumericalSimulation
What’s Next?
• Continue to investigate flow-rate dependence with more experiments on additional rocks
• Tests with vertical orientation
• Reliable methods for permeability mapping
• Reliable methods for capillary pressure mapping
• Theoretical foundation for observed multi-phase flows
• Parametric formulation for rate dependent relative permeability curves
• History matching experiments
• Sensitivity analysis• Simulation artifacts• Implication for large
scale processes
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Acknowledgements
• Post Doc – Jean-Christophe Perrin• Research Associate – Ljuba Miljkovic• Graduate Students – Michael Krause, Chia-
Wei Kuo, Ethan Chabora• GCEP sponsors
– ExxonMobil, Schlumberger, Toyota, GE
• ERE Department– Tony Kovscek, Louis Castanier, Roland Horne