PNNL-SA-95219
Simulating Geologic Cosequestration of Carbon
Dioxide and Hydrogen Sulfide
in a Basalt Formation
DIANA H. BACON, HERBERT T. SCHAEF AND B. PETER MCGRAIL
Pacific Northwest National Laboratory
Richland, WA
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
1
Overview
CO2 streams from coal-fired power plants may contain impurities,
including H2S, SOx, NOx, O2, N2, Ar, CO, Hg
Co-sequestered impurities could affect geologic storage, causing
changes in pH and oxidation state which affect dissolution and
precipitation reactions and the mobility of metals present in the
reservoir rocks
Sequestration of CO2 in depleted natural gas reservoirs or for
enhanced gas recovery also requires the capability to simulate gas
mixtures
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
2
STOMP-COMP
STOMP-COMP: Water, Components, Salt, Energy
Differs from previous operational modes of STOMP
Number of components is variable
Each phase has variable compositions
Applicable to deep saline reservoirs, as well as near-surface aquifers
Phase and component flexibility given by Peng-Robinson cubic
equation of state, EOS-COMP, with a flash equilibrium model where
phase composition is defined through fugacity equilibria
Aqueous concentration of each component linked to ECKEChem
reactive transport solver
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
3
EOS-COMP
Equation of state, EOS-COMP, can predict:
Properties (density, enthalpy, thermal conductivity and viscosity) of non
aqueous phase (NA) with multiple components
Peneloux (1982) volume shift correction provides better fit to density
data than standard Peng-Robinson
Friction theory model of Quinones-Cisnores et al. (2001) able to
provide accurate viscosities even at very high pressure
Thermal conductivity predicted using method of Stiel & Thodos (1964)
with parameter adjustments for polar compounds
Solubility of components with pure water or NaCl dominated brines
Aqueous binary interaction coefficients as a function of temperature
and salinity based on model of Soreide and Whitson (1992)
Component property database now contains 10 gases: CO2, O2, N2, Ar,
CH4, C2H6, C3H8, C4H10, H2S and SO2
Aqueous concentration of each component linked to ECKEChem
reactive transport solver
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
4
EOS-COMP Mixture Properties (CO2-H2S)
Density
Thermal
Conductivity
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
Enthalpy
Viscosity
5
Flood Basalt Features
Layered Basalt Flow
Formation process
Giant volcanic eruptions
Low viscosity lava
Large plateaus
Multiple layers
Primary structures
Thick impermeable seals
Caprock (flow interior)
Regional extensive interbeds
Permeable vesicular interflow zones
Injection targets
15-20% of average flow
Columbia River Basalt
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
6
Reactions Between Basalt and scCO2
containing 1% H2S (1285 days)
Experimental Conditions
1285 days
90°C
90 bar
Discrete individual growths on the basalt
Nodules, spheres, and globs
Typically contains pyrite inclusions
Carbonate chemistry is heavily substituted
with Fe2+, Mn2+, and Mg2+
Carbonate structure transitions from calcite to
ankerite/kutnahorite, similar to dolomite
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
7
Connecting Laboratory Results and
Batch Modeling to Reservoir Simulators
Geochemical reaction path
modeling with EQ3/6
EQ3/6 Geochemical Modeling
 Accurately predicts pyrite
precipitation followed by
carbonates
 Rapid consumption of H2S
 Correlatable to basalt
chemistry
These results feed into
reservoir simulations
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
8
Co-sequestration Simulation
14 days
2 years
4 years
1000 MT injection of 99% CO2
and 1% H2S in basalt
Supercritical fluid mixture
saturation (flood) and H2S
(contours) mole fraction in the
non-aqueous phase
Injection well is at X = 0
H2S is sequestered as pyrite
within 4 years
CO2 is sequestered as
carbonate minerals or
dissolved CO2 within 30 years
20 years
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
9
Phase Distribution of CO2 and H2S
H2S completely mineralized within 4 years
CO2 mostly mineralized within 30 years
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
10
pH
14 days
30 years
June 10-13, 2013
pH decreases from 9 to
4.55 after injection
Lowered pH drives
primary mineral
dissolution and secondary
mineral precipitation
Recovers to nearly neutral
pH after 30 years
pH is not significantly
different for 100% CO2
and 99% CO2–1% H2S
injections
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
11
Primary and Secondary Minerals
k25, mol/m2 s
Ea,
kJ/mol
15.26
Surface
Area,
cm2/g
23
2.75×10-13
69.8
2760
18.40
23
7.59×10-10
17.8
CaMgSi2O6
3280
12.89
19
7.76×10-12
40.6
Hedenbergite
CaFe(SiO3)2
3630
4.30
19
7.76×10-12
40.6
Mesostasis
Si0.548Al0.19Ca0.102Fe0.119K0.006Mg0.0826Mn0.0015Na0.0581Ti0.017O1.764
2650
38.25
22
7.17×10-08 (100ºC)
30.3
Magnetite
Fe3O4
5200
0.90
12
1.66×10-11
18.6
Anatase
TiO2
3900
0
10
6.92×10-12
37.9
Anhydrite
CaSO4
2960
0
10
6.46×10-4
14.3
Beidellite-Ca
Ca0.165Al2.33Si3.67O10(OH)2
2830
0
10
1.66×10-13
35.0
Beidellite-K
K0.33Al2.33Si3.67O10(OH)2
2790
0
10
1.66×10-13
35.0
Beidellite-Mg
Mg0.165Al2.33Si3.67O10(OH)2
2950
0
10
1.66×10-13
35.0
Calcite
CaCO3
2710
0
10
1.55×10-6
23.5
Chalcedony
SiO2
2650
0
10
5.89×10-13
74.5
Dawsonite
NaAlCO3(OH)2
2420
0
10
1.00×10-7
62.8
Dolomite
CaMg(CO3)2
2860
0
10
2.95×10-8
52.2
Pyrite
FeS2
5010
0
10
2.82×10-5
56.9
Rhodochrosite
MnCO3
3700
0
10
4.57×10-10
23.5
Siderite
FeCO3
3940
0
10
4.57×10-10
23.5
Mineral
Composition
Density,
kg/m3
Volume,
%
Albite-high
NaAlSi3O8
2610
Anorthite
CaAl2(SiO4)2
Diopside
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
12
Mineral Dissolution & Precipitation
Precipitation
99% CO2 + 1% H2S
100% CO2
Dissolution
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
13
Porosity & Permeability
Porosity
30 years
Perm, darcy
Porosity decreases from
10% to 9.65%
Permeability decreases
from 0.069 to 0.0625 darcy
Porosity/permeability
changes are not notably
different for 100% CO2 and
99% CO2–1% H2S
injections
30 years
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
14
Conclusions
Basalt formations are a viable option for long term storage of CO2
Both CO2 and H2S are rapidly mineralized
Porosity changes near wellbore would be relatively small for this pilotscale injection
The amount of H2S (1%) injected does not impact the proportion of
CO2 mineralized but causes variations in secondary minerals
Columbia River
= Iron and Sulfur
= Calcium
= Magnesium
June 10-13, 2013
IEAGHG Modelling and Risk Assessment Network
Meeting, Trondheim, Norway
15