(808b) CO2/Brine/Rock Interactions Under CO2 Sequestration Conditions

Authors: 
Soong, Y., National Energy Technology Laboratory (NETL), Office of Research and Development, Department of Energy, Pittsburgh, PA
Howard, B. H., National Energy Technology Laboratory
Hedges, S. W., U.S. Department of Energy
McIntyre, D., National Energy Technology Laboratory
Warzinski, R. P., U.S. Department of Energy, National Energy Technology Laboratory
Haljasmaa, I., US DOE/NETL
Crandall, D., National Energy Technology Laboratory (NETL), Office of Research and Development, Department of Energy



CO2/brine/rock interactions underCO2
sequestration conditions

Y. Soong*, B. H. Howard, S. W. Hedges, D.
McIntyre, R. Warzinski, G. Irdi, I. Haljasmaa1,and
D. Crandall1

U.S. DOE, National Energy Technology Laboratory,

P.O. Box 10940, Pittsburgh, PA 15236

1 URS Co.

It
has indicated by Intergovernmental
Panel on Climate Change Study that injection of CO2 into
confined geological formations, given their potentially massive carbon storage
capacity and widespread geographic distribution, represents one of the most
promising options for mitigating anthropogenically-induced
global climate change.  The
Mount Simon sandstone in the Midwest region of the U.S is recognized as
a promising candidate host reservoir for carbon sequestration. The Mount Simon
is a deep saline aquifer and is a primary reservoir target for large scale
carbon dioxide injection tests due to its proximity to CO2 sources,
favorable depth, thickness, permeability, porosity, and the presence of the
overlying Eau Claire Formation as a seal. 
The Midwest Geological Sequestration Consortium (MGSC)
has selected the Mount Simon as the reservoir at its major demonstration
project. While the Mount Simon Sandstone has ideal reservoir characteristics in
some areas, there are significant variations in porosity, permeability, and
mineralogy.

 

Numerous
studies have been conducted to investigate changes in host rock properties when
exposed to CO2.  Luquot and Gouze conducted CO2-enriched
fluid flow through a carbonate core sample under in situ sequestration
conditions (T = 100 °C and P = 12 MPa).  Under these conditions, a decrease in
permeability and porosity is seen that is linked to precipitation of Mg-rich
calcite.    Gouze
and Luquot also conducted an X-ray microtomography characterization study of porosity,
permeability and reactive surface changes during the dissolution of pure
calcite in a brine-CO2 mixture.  It  showed that the increase in
permeability is due to the decrease of the tortuosity
for homogeneous dissolution, whereas it is due to the combination of tortuosity decrease and hydraulic radius increase for
heterogeneous dissolution.  Jove Colon et
al., studied the
permeability, porosity and reactive surface area evolution during dissolution
of nonfractured, clay-free
Fontainebleau sandstone cores using a flow-through percolation reactor. The
experiments were performed at 80°C with 0.1 M NaOH
solution.  The permeability was found to
vary depending on where the dissolution occurred: in the pore void or the pore
throat.  Liu et al.,
conducted a simulation study of CO2 sequestration in the Mount Simon
sandstone via TOUGHREACT. They indicated that a strongly acidified zone (pH
3-5) forms in the areas affected by the injected CO2 and
consequently causes extensive secondary mineral precipitation (calcite, magnesite, ankerite, alunite and anhydrite) and dissolution of feldspars.  Thus, the injection of CO2 into a
deep saline aquifer affects porosity since it can cause both mineral
dissolution and precipitation in the formation. 
To predict if there will be any changes to the reservoir during
sequestration, it is critical to understand the behavior of the authigenic
minerals that line pore spaces when they are in contact with the CO2 saturated
brine.

  

An
experimental study was conducted to assess the impacts of injected CO2.
Core samples from the Mount Simon formation were placed in CO2
saturated brines at sequestration temperature of 85 °C and pressure of 23.8 MPa in the presence of synthetic Illinois Basin brine for a period of six months in a set of 1.3 liter
high-pressure vessels (17-4PH-1150 stainless steel, 10.2 cm I.D. x 16.5 cm
depth, manufactured by Thar Technologies, Inc.).  One sandstone sample with a porosity of 7.9% was
obtained at depth of 1,769.7 m from a well located in Vermillion County,
IN.  The other sample with a porosity of
1.4% was collected at depth of 2634.2 m from a well
located in Knox County, IN.  The major
mineral composition for the first sample is 78% quartz, 15% Feldspar and with
less than 2% microcline and trace minerals. 
The primary mineral composition of the second sample obtained from Knox
County is 70% quartz, 22% Feldspar, and around 4% illite/muscovite.  Micro CT, CT, XRD, SEM, petrography,
porosity, and permeability analyses were conducted prior to the six month
exposure.  Upon completion of the
experiment, the analyses were repeated.

The
permeability of the Vermillion sandstone after the six month exposure to CO2
and brine was 0.85 mD compared to 1.6 mD for the fresh sample. On the other hand, the
permeability of Knox sandstone was 69 nD compared to
50 nD for the fresh sample. The results suggest that
the exposure altered the pore characteristics and thus the permeability of the sample. Micro CT analysis as well as SEM backscattered images were used to
probe the Vermillion and Knox Co. sandstone before and after the six month
exposure to the CO2/brine environment.  It can be seen that mineral dissolution and
mineral precipitation occurred after the samples were exposed to CO2/brine
for six months.  Mineral precipitation
occurred in the Vermillion sample pores and cracks blocking flow and resulting
within the observed 50% decrease in permeability.  For the case of Knox sandstone, the mineral
dissolution occurred in pore though the precipitation was observed in the
exterior of the sample.  This might
result in increasing in permeability.  In
addition, from the analyses of the reacted brines within the reactor, it
indicated the possibly of Feldspar dissolution.

When
CO2 is injected into a saline formation, acidic conditions form in
the brine in the nearby portion of the reservoir thus reducing the pH of the
brine in the vicinity of the injection system. 
Minor minerals in the sandstone, such as K-feldspar, calcite, kaolinite, microcline etc., that are stable in the native
environment but not stable at lower pH can dissolve. Eventually, the increase
of cation concentration produced by mineral
dissolution can supersaturate the fluids with respect to other minerals.  If this occurs, precipitation of new minerals
can result in a change of porosity and permeability which could affect both CO2
storage capacity and fluid movement. The issue
is further complicated by the evolution of pore geometry due to these
geochemical reactions that may affect the
overall hydrologic properties of the host rock and therefore the performance of
the unit as an effective reservoir. 

The
decreasing permeability found in Vermillion sandstone was probably due to Feldspar
dissolution, migration and precipitation altering the sandstone pore/crack
structure.  For the case of sandstone
from Knox county, the permeability increased by 38%.  It might be due to the Feldspar dissolution
in the pore and mineral precipitation at exterior surface of the
sandstone.  Investigations are continuing
to more clearly elucidate the mechanisms and geochemistry of this system,
especially at the pore structure scale.

 

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