(714e) Nanoscale Reactions at CO2—H2Ο–Mineral Interfaces: Challenges in Monitoring CO2 in Geologic Sequestration

Recently, to help mitigate global climate-change and energy problems, much effort
has recently been devoted to developing methods for sequestering anthropogenic
CO₂ from coal-fired power plants. One of the most promising methods
is geological CO₂ sequestration (GS). To be successful, the techniques
and practices of sequestration must be effective, cost-competitive, and
environmentally friendly, as well as providing stable and secure, long-term
storage.^1-3In comparison with other types of sequestration, carbon
dioxide capture and storage in deep geological formations looks to be the most
promising option for mitigating the large volumes of CO₂ emissions
over the next century^1-3

Some prior studies of geological
CO₂ sequestration have mainly examined the physical processes that
occur during the sequestration of CO₂ in brine-saturated geological
formations. These studies take advantage of numerical modeling techniques that
employ such simulation programs as TOUGH2, or are primarily hydrological and geophysical approaches. Such approaches are based on the
assumption that supercritical CO₂, under sufficient pressure and
temperature (a minimum of  P = 7.4 MPa and T = 31.1 °C), is very stable for long
periods of time, and that the aqueous-phase diffusion of dissolved species and
leakage of dissolved CO₂ is insignificant.^4-7 However, these modeling exercises do not sufficiently
take into account the effects of dissolution/precipitation within mineral
phases, the adsorption/desorption of dissolved ions, or the
passivation/activation of mineral surfaces by free-phase or dissolved CO₂.
Neither do they consider
how all these different reactivities may adversely affect the effectiveness of
confinement and
overall safety of the
CO₂
that has
been injected.

Most recently, a Nature paper by Gilfillan et al.
reported that in seven gas fields with siliciclastic or carbonated reservoir
lithologies, dissolution of CO₂ in formation water is the dominant
sink for CO₂.⁸ They also reported
that maximum of 18% of loss of CO₂ can result in carbonate
precipitation. Therefore, long-term CO₂ storage models in similar
geologic systems should focus on the potential mobility in dissolved CO₂
in water. However, one important thing aspect is missing in this report that
even small quantities of carbonate precipitation can contribute significant
changes in porosity and permeability depending on the location of precipitates.
Therefore, we need to investigate the physical property changes at CO₂–H₂O-mineral
interfaces
in GS sites.

Changes in the porosity of the mineral phases
at the geological
formation
sites, especially the
dissolution
of the mineral phase or precipitation of secondary minerals in the pores, will
affect the fate and transport of CO₂ and the integrity of seals and the
matrix within the reservoirs. So
far, little
is known about the kinetics of the possible geochemical reactions of
supercritical CO₂ in brine and pre-existing mineral interfaces, or about the ultimate fate and transport of the injected CO₂.
Because
porosity and permeability can influence the physical properties of the
reservoir, it is important to be able to predict the porosity-permeability
evolution, as a function of the extent of reaction.

We investigated the physico-chemical property changes of
reference mineral samples (clay minerals) as well as field site samples
(sandstone and caprock from the Illinois Basin) by chemical reactions at CO₂–H₂O-mineral
interfaces. Our experiments were conducted under high pressures and
temperatures, which are comparable
to those
of GS sites. We
investigated whether reactions
between caprock and CO₂ (dissolved or supercritical) can change the
integrity of caprock and thus lead to leakage of CO₂. In general,
thick caprock is required for CO₂ sequestration, and its integrity
is prerequisite to the long-term safe storage of CO₂. However, the
minimum requirement for the thickness of caprock is still not determined.
Knowing the reaction rates of caprock in the presence of supercritical CO₂,
as well as the factors influencing the reaction rates, will help estimate the
minimum safe thickness of the caprock.

Our experimental results with caprock samples (CONSOL
coal mine sites, West Virginia) from the National Energy Technological
Laboratory indicate that after 14 days in contact with 1 atm CO₂
saturated saline water at 80°C, the concentrations of dissolved metals have
increased from zero to as high as 47,000 ppm. This suggests that the effects of
CO₂ on the integrity of caprock could be significant and need to be
further evaluated. In our experiments with caprocks and sandstones from GS
sites of the Midwest Geological Sequestration Consortium (MGSC), we found that
the most significant extent of dissolution occurs within a day with saline
water at P_CO2 = 1 atm and 80°C. This result implies
that monitoring the earliest stage of reactions of sandstone with CO₂
is crucial to understanding the CO₂-water-rock interactions in deep
saline aquifers.

The second
experiments investigated the effects of different reaction conditions (related
the different GS site conditions) on the reaction pathways and the extents of
reaction. Freshly cleaved
(001) surfaces of phlogopite (KMg₃(Si₃Al)O₁₀(F,OH)₂) were
prepared as thin layers (19-21
µm). Using in situ high pressure and temperature small angle
x-ray scattering (SAXS) reactor, the real time reactions were monitored.
Phlogopite was used to simulate the reactions in
deep saline aquifers in the presence of high pressure CO₂. The
experiments were conducted at P_CO2 = 1000 psi and different
temperatures (55, 75, and 95°C) in the presence of water. After CO₂
was injected into the microreactor, the scattering pattern changed due to
surface morphology changes (dissolution/precipitation) with time. This reaction
occurs significantly, even within one hour. After each experiment, each sample
was taken out of the reactor, and conducted atomic force microscope (AFM)
imaging to compare with our observations in SAXS setup.

By incorporating aqueous chemistry with in situ SAXS
and AFM, we monitored real-time
nanoscale
reactions resulting
from dissolution
of pre-existing minerals and precipitation of new mineral phases at CO₂-water-rock
interfaces under high pressure and temperature conditions. Those morphological changes
can be key information to understand the changes in porosity and permeability
in GS sites. The results will aid in designing secure and
environmentally acceptable CO₂ sequestration techniques.

References

1.    http://www-esd.lbl.gov/CO2GeoStorage/index.html

2.    Bruant, R. G.; Guswa, A.
J.; Celia, M. A.; Peters, C. A., Safe storage of CO2 in deep saline aquifers. Environ.
Sci. Technol. 2002, 36, (11), 240A-245A.

3.    Bachu, S., Sequestration
of CO₂ in geological media: criteria and approach for site selection
in response to climate change. Energy Conversion and Management 2000,
41, (9), 953-970.

4.    Doughty, C.; Pruess, K.,
Modeling supercritical carbon dioxide injection in heterogeneous porous media. Vadose
Zone Journal 2005, 3, (3), 837-847.

5.    Spycher, N.; Pruess, K.;
Ennis-King, J., CO₂-H₂O mixtures in the geological
sequestration of CO₂. I. Assessment and calculation of mutual
solubilities from 12 to 100 degrees C and up to 600 bar. Geochim. Cosmochim.
Acta 2003, 67, (16), 3015-3031.

6.    van der Meer, L. G. H.,
The CO₂ storage efficiency of aquifers. Energy Converv. Manage. 1995,
36, (6-9), 513-518.

7.    Talman, S. J.; Adams, J.
J.; Chalaturnyk, R., Adapting TOUGH2 for general equations of state with
application to geological storage of CO2. Computers & Geosciences 2004,
30, (5), 543-552.

8.    Gilfillan, S. M. V.;
Lollar, B. S.; Holland, G.; Blagburn, D.; Stevens, S.; Schoell, M.; Cassidy,
M.; Ding, Z. J.; Zhou, Z.; Lacrampe-Couloume, G.; Ballentine, C. J., Solubility
trapping in formation water as dominant CO2 sink in natural gas fields. Nature
2009, 458, (7238), 614-618.