correspondence
Caprock corrosion
a
Argon 1st cycle
CO2 flow test
CO2 1st cycle
CO2 flow test
CO2 2nd cycle
CO2 flow test
CO2 3rd cycle
10–19
H2O flow test
H2O 1st cycle
H2O flow test
H2O 2nd cycle
Argon (postCO2 saturated water flow)
b
BEFORE
Quartz
Pore
Chlorite
Siderite
50 mm
c
Permeability (m2)
To the Editor — The storage of naturally
and industrially produced carbon dioxide
in depleted hydrocarbon reservoirs
and aquifers is viewed as an essential
component of the strategy to combat
the build-up of greenhouses gases in
the atmosphere1. The success of these
projects relies on the long-term integrity
of low-permeability caprocks that must
seal the CO2 within the reservoir 2,3.
However, we find that the integrity of
caprock can be altered by flowing CO2saturated aqueous fluid. Specifically,
fluid flow under laboratory conditions
through siltstone caprock sampled at
one of the world’s largest carbon storage
projects, In Salah in Algeria4, increases the
permeability of the caprock by one order
of magnitude under simulated reservoir
conditions. The increase in permeability is
caused by chemical reactions between the
CO2-rich fluid and minerals commonly
found in caprocks. We therefore argue
that such geochemical interactions
must be considered in geological carbon
sequestration projects.
The geological sequestration of CO2 is
currently under investigation in field trials
at sites including Weyburn in Canada5,
Sleipner in the North Sea6 and In Salah in
Algeria4. For carbon capture and storage to
succeed, the integrity of the reservoir must
be preserved over thousands of years.
The injection of CO2 into saline aquifers
and depleted hydrocarbon reservoirs
inevitably alters the geochemical conditions
of the reservoir (see Supplementary
Information), but little is known about
the effect of CO2 injection on the physical
properties of the reservoir and caprocks.
Pure CO2 is considered to be relatively
inert in the rock matrix. However, contact
with water leads to solution of the CO2,
the creation of carbonic acid and partial
dissociation leading to reduced fluid pH
(ref. 7). When CO2 has been injected into
oil fields for the purpose of enhancing
oil recovery, the acidic CO2-rich aqueous
fluids created in the subsurface reservoir is
known to interact geochemically with rockforming minerals7.
To test the influence of CO2-saturated
fluid flow on caprock integrity, we selected
a typical sample from the base of the
caprock sequence of the Krechba gas field at
In Salah. Here, about 0.5 megatons of CO2
are being injected into the subsurface each
Chlorite
AFTER
Permeability increase
Pore
10–20
Siderite
Quartz
10
20
30
40
50
Effective pressure (MPa)
60
70
Figure 1 | Changes in permeability and microstructure of a sample of caprock from In Salah, Algeria,
caused by various pore fluids. a, Permeability measured using various single-phase pore fluids over a
range of effective pressures shows no change. Measurements made after CO2-saturated water flow show
permeability has increased by approximately 8-fold. b,c, Scanning electron microscope images before (b)
and after (c) the flow of CO2-saturated water. Dissolution of the minerals chlorite and siderite increases
pore throat radii and hence porosity.
year (see Supplementary Information). The
Lower Carboniferous caprock at In Salah
is a 950-m-thick mudstone, of which the
lower part is a thinly bedded estuarine
siltstone that contains no organic material
or swelling clays8,9. Mineralogical analyses
of the lower part of the caprock show the
presence of the dominant silicate minerals
quartz, illite and potassium feldspar, with
subordinate quantities of chlorite and
kaolinite, and small quantities of siderite
and pyrite8. Extensive characterization of
the lower caprock3,8 confirmed that our
sample was representative of the lower
caprock as a whole.
In the laboratory, we investigated
experimentally whether any changes in
caprock permeability could be attributed
to pore-fluid–rock interactions (Fig. 1). We
used a high-pressure permeameter 9 and
replicated in situ reservoir-stress conditions
at room temperature (see Supplementary
Information). We first measured the initial
permeability of the sample of caprock
using argon — an inert pore fluid — over a
range of effective pressures. Subsequently,
we used dry CO2 and then distilled water
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to again measure permeability over the
same pressure range. Experiments using
each of these single-phase fluids gave
the same values for permeability (within
experimental uncertainty) over the same
pressure range. We also varied the method
for permeability measurement, using
both the pulse transient and constant flow
methods. The method of permeability
measurement had no effect on the result.
We then flowed CO2-saturated water
through the sample at approximate
reservoir pressure conditions (45 MPa
confining pressure, 20 MPa pore pressure
and 25 MPa effective pressure) for 72 hours
(Supplementary Fig. S3). The flux of fluid
through the sample during the experiment
was 0.015 cm3 hr–1, which equates to a
volume of fluid that is about 4.07-times
that of the pore volume of the sample. We
found that the permeability of the caprock
sample increased by approximately a
factor of 8 during the experiment (Fig. 1).
The pressure difference across the sample
decreased throughout the experiment as
the permeability increased (Supplementary
Fig. S3).
79
correspondence
The sample was then placed in a vacuum
oven to remove any remaining pore fluid.
Using inert argon, we performed a series of
pulse transient permeability measurements
across the range of effective pressures
previously used for the other pore fluids.
This final experiment confirmed that
permanent change in the permeability of
the caprock had occurred as a result of the
passage of CO2-saturated water through the
sample (Fig. 1).
Mechanical effects can be discounted
as the cause of the change because the
permeability of the caprock was unaffected
by the flow of either dry CO2 or distilled
water. The increase in permeability
during the flow of CO2-saturated water
has most probably been caused by
geochemical processes.
Petrophysical analyses before and after
the CO2-saturated water flow test showed
that the sample porosity increased from 7 to
10%, its weight decreased from 6.83 to 6.39 g
and the internal surface area decreased
from 0.901to 0.423 m2 g–1. We used X-ray
diffraction to compare the mineral content
of an unaffected caprock sample to that
of our experimental sample. The caprock
that had been subject to CO2-saturated
fluid flow showed significant loss of the
mineral cements siderite (iron carbonate)
and chlorite (iron-rich aluminosilicate clay)
(Supplementary Fig. S2).
Scanning-electron microscope
examination of polished thin sections of the
experimental sample revealed a substantial
change to the typical pore network and
confirmed the dissolution of siderite and
chlorite from the sample, both in pores and
in pore throats (Fig. 1). These changes were
80
fairly uniform throughout the sample, and
did not seem focussed along preferential
pathways. The loss of chlorite and siderite
caused a net increase in porosity and opened
up pore throats, leading to a corresponding
increase in permeability. This finding is
consistent with previous results based on
crushed bulk rock samples3,10.
Typical reservoir temperatures are
about 95 °C — much higher than our room
temperature experiments. A higher in situ
temperature would probably increase
reaction rates, so the permeability increase
could occur on shorter timescales than
in our experiments. Higher temperatures
may also result in a marginally different
pH of the fluid. Although the experimental
temperature used is below the critical
temperature for CO2, the fluid pressure
used is much greater than the critical
pressure. Consequently, the CO2 should
not experience any phase changes owing to
higher temperature at reservoir conditions:
the liquid will only become less dense.
The overall integrity of the caprock
seal as a whole may not necessarily be
compromised. Reaction between the pore
fluid and caprock is likely to occur only in
the immediate vicinity of the caprock–fluid
interface, close to the injector wells in a
reservoir. Furthermore, minerals dissolved
at one location may precipitate elsewhere,
in parts of the caprock with lower chemical
potential, some distance along the flow path
in the reservoir. Thus, caprock integrity
might actually be enhanced in these regions
and may ameliorate the local permeability
increase. The balance between dissolution
and precipitation within caprock horizons
requires further investigation.
Our results show that the chemistry of
fluids injected into carbon sequestration
systems can significantly alter the physical
properties of the overlying caprock. Our
study was performed on rock from the
In Salah project, but may be applicable to
other existing, or future, carbon storage
sites: the minerals lost during the reaction
are common constituents of a variety of
caprock types. Our results do not imply
that carbon storage sites will necessarily
leak over time, but they illustrate that
reactive fluid flow at carbon storage sites
should be a fundamental consideration
before routine large-scale injection of
CO2 commences.
❐
References
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Capture and Storage (Cambridge Univ. Press, 2005).
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12, 9 (2011).
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M. in Greenhouse Gas Control Technologies Vol. 1 (eds Gale, J. &
Kaya, Y.) 595–600 (2003).
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(eds Gale, J. & Kaya, Y.) 1629–1632 (2003).
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Dioxide Vol. 233 (eds Baines, S. & Worden, R. H.) 211–224
(Geological Society Special Publication, 2004).
8. Armitage, P. J. et al. Mar. Petrol. Geol. 27, 1395–1410 (2010).
9. Armitage, P. J. et al. J. Geophys. Res. 116, B12208 (2011).
10. Czernichowski-Lauriol, I. et al. in Final Report of JOULE II Project
CT92–0031: The Underground Disposal of Carbon Dioxide (ed
Holloway, S.) 183–276 (British Geological Survey, 1996).
P. J. Armitage, D. R. Faulkner* and R. H. Worden
Department of Geology and Geophysics,
School of Environmental Sciences, University of
Liverpool, Liverpool, L69 3GP, UK.
*e-mail: faulkner@liv.ac.uk
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