Subsurface monitoring of anthropogenic CO2 injected in sedimentary
basins: Results from the Frio-I brine test, Texas, USA
Yousif K. Kharaka & James J. Thordsen
U. S. Geological Survey, Menlo Park, California, USA
Susan D. Hovorka & H. Seay Nance
Bureau of Economic Geology, University of Texas, Austin, Texas, USA
David R. Cole & Tommy J. Phelps
Oak Ridge National Laboratory, Oak Ridge, TN 37831, USA
Kevin G. Knauss
Lawrence Livermore National Laboratory, Livermore, California, USA
ABSTRACT: To investigate the potential for the long-term storage of CO2 in deep saline aquifers, 1600 t of
CO2 were injected at 1500 m depth into a 24-m-thick “C” sandstone of the Frio Formation near Houston,
Texas. Fluid samples obtained before CO2 injection from the injection well and an observation well 30 m updip showed a Na-Ca-Cl type brine with ~93,000 mg/L TDS at saturation with CH4, but only 0.3% CO2. Following CO2 breakthrough, samples showed sharp drops in pH, pronounced increases in alkalinity and Fe, and
significant shifts in the isotopic compositions of H2O, and DIC. These parameters, together with perfluorocarbon tracer gases were used for monitoring migration of injected CO2 into the overlying Frio “B”, a 4-m-thick
sandstone, separated from the “C” by ~15 m of shale and siltstone beds. Results from “B” 6 mo after injection
show significant CO2 (2.9 % vs. 0.3% CO2) migration into the “B” sandstone. Results of samples collected 15
mo after injection, however, show no indications of additional CO2 in the “B” sandstone.
1 INTRODUCTION
Global warming and the resulting climate change are
arguably the most important environmental challenges facing the world in this century (White et al.
2003). There is now a broad scientific consensus that
global warming results primarily from increased
concentrations of CO2 and other atmospheric greenhouse gases emitted largely from the burning of petroleum and coal (Broecker 2006). Increased anthropogenic emissions of CO2 have raised its
atmospheric concentrations from ~280 ppmv during
pre-industrial times to ~380 ppmv today, and are
projected to increase to up to 1,100 ppmv by 2100.
Carbon sequestration, in addition to energy conservation and increased use of lower carbon intensity
fuels, is now considered necessary to stabilize atmospheric levels of greenhouse gases and global
temperatures at values that would not severely impact economic growth (White et al. 2003). Sedimentary basins in general and deep saline aquifers in particular, are considered attractive as repositories for
large amounts of anthropogenic CO2, because they
have huge potential capacity, and advantageous locations close to major CO2 sources (Hitchon 1996).
In geologic sequestration, CO2 captured from
power plants may be stored in: 1) structural traps
such as depleted petroleum reservoirs, primarily as
supercritical fluid (hydrodynamic trapping); 2) saline
formation water as H2CO3o, HCO3- and other dissolved species (solution trapping); and/or 3) car-
bonate minerals, including calcite, magnesite and siderite (mineral trapping) (Hitchon 1996). Initially,
the bulk of injected CO2 will be stored as supercritical fluid because the target reservoirs are likely to
have temperatures and pressures higher than 31°C
and 74 bar, the critical values for CO2. The injected
CO2 will rapidly dissolve in formation water that
contacts the fluid, but mineral trapping would be
slower, yet more permanent. In addition to storage
capacity, key environmental questions include CO2
leakage related to the storage integrity and the physical and chemical processes that are initiated by injecting CO2 underground (Hepple & Benson 2005).
In this summary, we discuss geochemical results
from Frio-I, a US DOE-funded multi-laboratory field
experiment to investigate the potential for geologic
storage of CO2 in saline aquifers. We emphasize
temporal changes in fluid compositions in the injection sandstone, the Frio “C”, and deep monitoring of
fluid leakage from “C” into the overlying “B” sandstone. Data obtained for deep monitoring above the
injection zone proved more conclusive than results
obtained from four shallow groundwater wells and
soil gases in the vadose zone.
2 REGIONAL SETTING AND METHODOLOGY
The Frio site is located within South Liberty oil
field, near Dayton, Texas, a region of the Gulf Coast
where industrial sources of CO2 are abundant. Wells
in this field were drilled in the 1950s, with production from the Eocene Yegua Fm at ~2900 m depth.
An inactive oil well was recompleted and perforated
in the Frio “C” sandstone at 1,528–1,534 m for use
as an observation borehole. About 30 m down-dip, a
new CO2 injection well was drilled and perforated
also in Frio “C” at 1,541–1,546 m. The Frio Fm
comprises several reworked fluvial sandstone and
siltstone beds, separated by transgressive marine
shale. The Frio “C” injection zone is a subarkosic fine-grained, moderately sorted quartz and feldspar
sandstone, with minor amounts of illite/smectite and
calcite. The zone has high mean porosity of ~32%
and permeability of 2–3 Darcies. Situated above the
“C”, the “B” sandstone has a ~4 m thick reworked
fluvial sandstone bed at the top, but is separated
from “C” by ~15 m of shale, muddy sandstone and
siltstone beds (Fig. 1). However, the main barrier to
CO2 leakage to surface is expected to be the overlying regional thick marine shale beds of the MioceneOligocene Anahuac Fm (Hovorka et al. 2006).
Approximately 1,600 t of CO2 were injected during October 4–14, 2004. More than 60 samples of
water and gas were obtained from the “C” sandstone
of both wells before, during and following CO2 injection, using a variety of tools and methodologies
(Kharaka et al. 2006), including a novel downhole
U-tube system (Freifeld et al. 2005).
Figure 1. Open-hole logs of the injection well. Note the relatively thick beds of shale and siltstone between Frio “C” and
“B” sandstones.
Surface and downhole fluid samples were also
obtained (April 4-6, 2005) from the Frio “B” of the
observation well, which was perforated (1506.01508.5 m) after cementing the earlier “C” perforations. Samples were collected after >300 bbl of brine
were produced, and values of EC, pH, and alkalinity
became constant, and concentrations of Rhodamine
WT, the tracer used to tag the drilling fluids, were
below background value of ~1 µg/L. To completely
prevent any CO2 leakage from “C” to “B” through
the earlier “C” perforation into the well casing, a
plug was inserted between them before the final and
more intensive fluid sampling carried out on January
23-27, 2006. Again sampling was initiated after values of EC, pH, and alkalinity became constant, and
Rhodamine WT reached background values, which
occurred after ~200 bbl of brine was produced.
3 RESULTS AND DISCUSSION
Chemical analysis of formation water and gas samples obtained from both wells prior to CO2 injection
show that the Frio brine is a Na-Ca-Cl type water,
with a salinity of 93,000±3,000 mg/L TDS. The
brine also has relatively high concentrations of Mg
and Ba, but low values for SO4, HCO3, and DOC
(Kharaka et al. 2006). The high salinity and the low
Br/Cl ratio (0.0013) relative to sea water indicate
dissolution of halite from the nearby salt dome.
Careful measurements of the volumes of water and
evolved gas obtained with downhole samplers show
the Frio brine to have 40-45 mM dissolved CH4,
which is close to saturation at reservoir conditions
(65oC and 150 bar). Results show that CH4 comprises 95±3% of total gas, but dissolved CO2 content is
low at ~0.3% (Table 1).
During the CO2 injection, October 4-14, 2004,
~40 water samples were collected from the observation well, and on-site measurements showed only
subtle increase in EC from a pre-injection value of
~120 mS/cm (at ~22C), but major changes in some
chemical parameters as the CO2 reached the observation well, including a sharp drop in pH (from 6.5 to
5.7) and high increases in alkalinity (from100 to
Table 1. Composition of gases (mole %) from Frio “C” and
“B” sandstones. Note the relatively high CO2 in 3“B”.
1
2
3
4
Gas
“C”
“C”
“B”
“B”
He
0.008
0
0.01
0.011
H2
0.040
0.19
0.92
0.012
Ar
0.041
0
0.13
0.010
CO2
0.31
96.8
2.86
0.28
N2
3.87
0.037
1.51
1.12
CH4
93.7
2.94
94.3
98.3
C2H6+
1.95
0.005
0.12
0.11
1 – background from injection well, before CO2 injection; 2 –
from observation well after CO2 breakthrough; 3 – from observation wells ~ 6 mo after injection; and 4 – from the observation well ~ 15 mo after injection.
3,000 mg/L as bicarbonate). Additionally, laboratory
determinations showed major increases in dissolved
Fe (from 30 to 1,100 mg/L) and Mn, and significant
increases in the concentration of Ca (Kharaka et al.
2006). The most dramatic changes in chemistry occurred at CO2 breakthrough 51 hours after injection,
as evidenced also by on-site analysis of gas samples
from the U-tube system (Freifeld et al. 2005) that
showed CO2 concentrations increasing from 0.3 to
~97% of total gas , with CH4 comprising the bulk of
the remaining 3% (Table 1). Results showed significant shifts in the isotopic compositions of H2O, DIC
and CH4 following CO2 injection.
Results of geochemical modeling, using modified
SOLMINEQ (Kharaka et al. 1988) indicate that the
Frio brine in contact with the supercritical CO2
would have a low initial pH of ~3 at subsurface conditions, which would cause the brine to become
highly undersaturated with respect to carbonate,
aluminosilicate and other minerals in the Frio (Fig. 3
in Kharaka et al. 2006). Because mineral dissolution
rates are generally higher by orders of magnitude at
such low pH values, the observed increases in concentrations of Ca and equivalent concentration of
HCO3 likely result from the rapid dissolution of calcite, as depicted in reaction (1).
CO2(g) + H2O + CaCO3(s) = Ca2+ + 2HCO 3
(1)
The large increases observed in concentrations of
Fe and equivalent bicarbonate could result from dissolution of siderite, but no siderite was observed in
the retrieved core. Hence these increases could be
caused by dissolution of the observed iron oxyhydroxides, depicted in the redox-sensitive reaction
(2).
2Fe(OH)3(s) + 4H2CO 30 + H2(g) = 2Fe2+ + 4HCO 3 +
6H2O
(2).
However, some of the increases in Fe and equivalent bicarbonate could also result from corrosion of
pipe and well casing that contact low pH brine
(Kharaka et al., 1980; Ahmad, 2006), as indicated by
the redox-sensitive reaction (3).
Fe(s) + 2H2CO 30 = Fe2+ + 2HCO 3 + H2(g)
environmental implications with regard to creating
pathways in the rock seals and well pipes and cements that could facilitate leakage of CO2 and brine.
Maintaining reservoir integrity that prevents the ultimate escape of CO2 back to the atmosphere by limiting its leakage to extremely low levels is essential
to the success of injection operations (Hepple &
Benson 2005). Preventing brine and CO2 leakage into overlying sources of drinking water is also important, because toxic organic and inorganic chemicals are mobilized by the injected gas, in addition to
those present in the pristine brine (Kharaka 2006).
Results of chemical analysis of samples collected
~20 d, 6 and 15 mo after CO2 injection demonstrate
decreases in the concentrations of Fe, Mn (Fig. 2),
HCO3 and Ca, and increases in pH. Geochemical
modeling indicates that the brine pH increases from
dissolution of carbonate and iron oxyhydroxide minerals discussed, as well as from dissolution of oligoclase and other minerals present in the Frio. Aluminosilicate mineral dissolution generally follows an
incongruent reaction (4), where dawsonite, gibbsite
and amorphous silica are precipitated, and/or where
kaolinite and amorphous silica are precipitated
(White et al. 2003; Knauss et al. 2005).
0.4H+ + Ca.2Na.8Al1.2Si2.8O8(s) + 0.8CO2(g) +
1.2H2O = 0.2Ca2+ + 0.8NaAlCO3(OH)2(s) +
0.4Al(OH)3(s) + 2.8SiO2(s)
(4)
As the brine pH increases from mineral interactions and the mixing of CO2-saturated and pristine
brines, modeling indicates that mineral saturations
trend towards supersaturations, resulting in precipitation of carbonate and other minerals. The overall
result is the brine gradually evolving toward its preinjection composition. Additional fluid sampling is
planned for Frio-II to further investigate gas-waterrock interactions, and the source of Fe and other
metal increases as a result of CO2 injection.
(3)
Similar reactions may be written for Mn that increased from 3–18 mg/L. There were also increases
in the concentration of other metals, including Zn,
Pb and Mo, which are generally associated (sorbed
and coprecipitated) with iron oxyhydroxides, but
could also be present in the low-carbon steel pipe
used in petroleum wells (Ahmad, 2006).
The chemical data coupled with geochemical
modeling indicate rapid dissolution of minerals, especially calcite and iron oxyhdroxides and possibly
pipe corrosion caused by low pH values of the brine
that had contacted the injected supercritical CO2.
Such rapid mineral dissolution could have important
Figure 2. Concentrations of Fe and Mn in Frio-I brine from 6,
2004 to 1, 2006. Note the sharp increases in metal content during October 6, 2004, at the time of CO2 breakthrough, and
slightly higher Fe and Mn in “B” samples from April, 2005.
3.1 Subsurface monitoring
Monitoring at and close to the surface for CO2 leakage signal in soil gas was not effective primarily because of the induced perturbations as a result of injection operations. Significant amounts of CO2 were
released during injection, and venting of CO2 with
perfluorocarbon (PFT) and other tracer gases during
the purge cycle of the U-tube sampling system, released tracer to the atmosphere and the soils around
the wells. Monitoring results obtained from the four
shallow groundwater wells showed rapid chemical
changes during the monitoring period, with a preinjection region of high salinity water migrating
down-gradient across the monitoring array. Groundwater monitoring is continuing, but the observed
chemical changes are tentatively attributed to the extraction of large amounts of groundwater for drilling
and other field operations and to the construction of
a large fresh-water mud disposal pit (Hovorka et al.
2006).
Because of the anticipated difficulty of near surface monitoring, we planned a rigorous program for
monitoring immediately above the injection zone.
Results of brine and gas analyses from the “B” sandstone, first perforated and sampled six months after
CO2 injection, showed slightly elevated concentrations of bicarbonate, Fe, and Mn and significantly
depleted 13C values (-5.9 to -17.5 vs. ~-4‰) of
DIC relative to preinjection “C” composition. A
more definitive proof of the migration of injected
CO2 into the “B” sandstone is obtained from the
presence of two of the four (PMCH and PTCH) PFT
tracers added to the injected CO2 (Phelps et al.
2006). Additional proof of the migration of injected
CO2 into the “B” sandstone is obtained from the
high concentration (2.9 vs. ~0.3%) of CO2 in dissolved gas obtained from one of the two downhole
Kuster samples (Table 1).
Results of samples collected in January 23-27,
2006 gave brine and gas compositions that are approximately similar to those obtained from the “C”
sandstone before CO2 injection. These results indicate the absence of significant amounts of injected
CO2 in the “B” fluids sampled. However, a contrary
conclusion is indicated from the fact that PMCH and
PTCH were measured in the six samples also analyzed for PFT tracers (Phelps et al. 2006). It is possible that the measured PMCH and PTCH represent
desorbed PFT tracers that were introduced into “B”
earlier and do not require migration of additional injected CO2 into the “B” sandstone.
The main conclusion from results obtained from
the “B” sandstone is that significant amounts of CO2
migrated from the “C” to the “B” sandstone. We can
not rule out migration through the intervening beds
of shale, muddy sandstone and siltstone, but a more
likely path is a short-term leakage through the failed
squeeze on perforations in the “C” or remedial cement around the casing of a 50-year old well. These
results highlight the importance of investigating the
integrity of cement seals and pipes, especially in reused abandoned wells, prior to the injection of large
quantities of reactive and buoyant CO2.
ACKNOWLEDGMENTS
We thank G. Ambats, E. Kakouros and B. Topping
for helping with sampling and analyses, and D. Collins and others at Sandia Technologies for logistical
support. Funding was provided by US. DOE
(NETL). (William O’Dowd, Program Coordinator).
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