P R E P R I N T – ICPWS XV
Berlin, September 8–11, 2008
Impact of Mutual Solubility of H2O and CO2 on Injection Operations for Geological
Storage of CO2
Suzanne Hurter, Diane Labregere, Johan Berge and Arnaud Desitter
Schlumberger Carbon Services, Paris
[email protected]
Interactions between injected CO2 and the brine in the pores of a subsurface reservoir may strongly affect
injection operations for long-term geological CO2 storage. As a continuous stream of CO2 is injected into a
reservoir, the water is continuously extracted from the brine, to the point that the irreducible water saturation
may attain zero. This dry-out effect results in enhanced injectivity in a low salinity environment. In formations
saturated with highly saline brine, however, injectivity is impaired. Here, the brine becomes supersaturated
w.r.t. the salts dissolved in it as H2O continues to evaporate into the CO2 and salt (generally halite or NaCl)
precipitates in the pores. The porosity and permeability diminish, some times to the point at which a well may
completely plug up and may have to be abandoned.
We present simulations performed with a commercial compositional code to illustrate these phenomena.
Choices of injection strategy, injection interval as well as rock properties are shown to significantly affect the
amount and the spatial and temporal distribution of salt precipitation. The influence of relative permeability
and capillary pressure is especially dramatic: all conditions being the same, unimpeded injection over the
decades to complete plugging of the injection well within a few days is possible in the models. Models also
show that pre-flushing the reservoir with lower salinity fluid may prevent salt precipitation. Laboratory
expemiments are needed to validate and calibrate the models before application to field operations.
Introduction
One option for long-term CO2 storage with the
purpose of greenhouse emissions reduction is the
injection of this gas into saline aquifers. ‘Saline
aquifer’ is understood here as a brine reservoir or
geological formation with reservoir characteristics
(porosity and permeability) and pores filled with
brine. The term ‘saline’ expresses that CO2 storage
is planned in reservoirs not intended to be used as
fresh water resources.
Often this kind of geological formation is not
well known compared to areas for hydrocarbon or
mining exploration. Data coverage is sparse and
uncertainty large. Therefore, simulations play an
important role to explore a range of possible
scenarios and help constrain geologic risk of
potential CO2 storage sites.
Injection of CO2 into brine forms always an
immiscible system. Generally, CO2 is less dense
than brine and exhibits a strong gravitational drive
(buoyancy).
The mutual solubility between CO2 and brine
affects the injection process and flow properties in
three ways:
1. CO2 dissolves in the brine increasing its
density. The CO2 enriched brine may sink [1].
CO2 dissolves in brine and reacts with water
forming an acid, inducing chemical reactions
between the fluids and the solid rock matrix
[2].
3. H2O dissolves or vaporizes into CO2,
removing water from the brine and increasing
its salinity. This may lead to dry-out and in
some cases salt precipitation around the
injection well. Salt precipitation may disturb
injection operations and need to be
remediated.
In this article, we first discuss in more detail the
impact of mutual solubility for CO2 storage in
saline aquifers. Then numerical models are
presentented for the case of high salinity reservoirs.
We focus on looking into the factors that influence
amount and distribution of precipitation and test the
mitigation options of adjusting injection strategy
(rate) and pre-treating the reservoir with a dilute
fluid preceeding CO2 injection. Simulations for a
very simple geometry for a CO2 injection well
illustrate impact on operations and mitigation
options.
2.
Mutual Solubility of CO2 and H2O
CO2 solubility in brine increases with pressure
and diminishes with increasing temperature. The
accordingly. The mutual solubility of CO2 and
water includes a correction for salinity [7,8]. The
salinity of the brine is adjusted accordingly until the
saturation threshold is reached and halite is
precipitated. These functionalities allow processes
such as dry-out and salting-out to be simulated in a
large variety of geological environments.
Here the possible brine components are H2O,
CO2, NaCl and CaCl2. Halite (NaCl) precipitates
whenever, in a time step and cell, the saturation of
NaCl is reached using an empirical relationship of
halite saturation as a function of temperature [4]. At
each time step this value is compared to the NaCl
concentration in the brine. The excess amount is
removed from the brine (density is adjusted) and
added to the solid saturation, i.e. the amount of
porosity occupied by precipitate.
The effect of precipitation on the porosity is
calculated from the mass of solid formed and the
density of the minerals that are precipitated in the
pores. The impact of the porosity change on
permeability is a classical unsolved problem. Some
minerals grow in large pores, while others are
found preferentially in pore throats. In the first case,
permeability may not be affected much, while in
the second permeability may change dramatically
even if porosity does not change significantly. A
large body of scientific literature presents and
discusses many models correlating porosity change
to permeability change based on laboratory
experiments, well log interpretation as well as
scaling and diagenetic studies [9].
In the simulation models presented here,
precipitation is captured through a solid saturation
(Ss) concept that affects the volume available to
fluid movement in the pores. This is expressed by:
greater the brine salinity, the less CO2 will dissolve
into it. Salinity is generally expressed as Total
Dissolved Solids (TDS) that can be obtained by
evaporating water from a sample and measuring the
mass of salts that precipitates out. Brines contain a
variety of chemical species that compose density
and salinity. Brine composition depends on its
chemical evolution and reservoir rock composition
[3]. In many brines the amount of Na and Cl is
orders of magnitude greater than the other
components and a simplification is made: salinity
(TDS) is completely attributed to NaCl (halite).
H2O is not very soluble in supercritical CO2.
However, a continuous stream of CO2 being
injected into a geological formation, will cause a
region around the injection well to dry out. As the
water of the formation brine is continuously extracted, even the irreducible water saturation (Swirr)
may reduce to practically zero, increasing the
effective permeability. Enhanced injectivity is the
result in low-salinity brine environments [4].
As dry-out progresses, the salinity and density
of the brine increase and it becomes supersaturated
w.r.t. to the salts it contains. In the near wellbore
area and in wells, pipes and other facilities, this
phenomenon is refered to as scaling or salting out.
The saturation state of a specific mineral and
sequence of precipitation of various salts will be
influenced by other cations and anions present.
Once salts precipitate, the porosity and permeability diminish. In high-salinity brine
environments, the most important type of scale is
halite. This phenomena is also known in operations
involving injection and production of natural
hydrocarbon gas [5].
The models presented later focus on the
influence of various factors on the amount and
distribution of precipitation.
V f = (1 − S s ) ⋅ V p
where, Vf is the volume of fluid and Vp the pore
volume in a grid cell. The impact of precipitation
(solid saturation) on fluid flow is implemented with
a mobility multiplier. The user may choose the
severity of flow impairment caused by salt
precipitation by allocating values to the mobility
multiplier. The values will be the result of expert
judgement based on detailed knowledge of the
system under investigation, hopefully calibrated
with core flood experiments. Fig. 1 presents the
relationship used in this article, which is arbitrary.
The mobility of the fluid decreases with increasing
solid saturation up to 0.8, that is, when 80% of the
pore space is filled with precipitate, permeability is
assumed to reduce to zero. At a solid saturation of
0.4, for example, the absolute (intrinsic)
permeability would be multiplied by 0.35.
Numerical Implementation
The simulation tool used here is a commercial
compositional code used extensively in the oil and
gas industry. The functionalities relevant to this
article are described here. Additional capabilities
are described in the references [4, 6]. The code has
the capability of computing accurately the physical
properties (density, viscosity, compressibility, etc.)
of pure and impure CO2 as a function of
temperature and pressure. Water partitions into the
CO2-rich phase and changes of the properties of the
mixture (density, viscosity) that affect its flow.
Similarly, CO2 partitions into the water-rich phase
causing its density, viscosity and salinity to change
2
permeability and capillary pressure. Fig.3 displays
relative permeability curves for the (a) Basal
Cambrian, (b) Viking and (c) Ellerslie sandstones.
Details can be found in [12,13]. The shapes of the
curves that can be fit are slightly different and the
irreducible water saturation (Swirr) is different, 30,
55 and 65%, respectively. The irreducible water
saturation determines the maximum relative
permeability CO2 can obtain.
Boundary conditions. The top and bottom
boundary are impermeable and the outer boundary
is described by numerical aquifers that simulate a
constant hydraulic gradient and have the same
properties than the reservoir [6].
Initial conditions. Before injection starts the
reservoir pressure is hydrostatic: 75 bar at 730 m
depth. Porosity is homogeneous and isotropic at
20%.
History. Three models are run. In the first
injection of CO2 at a rate of 53 000 m3/day is
initiated at t=0 and an initial injectio pressure of 85
bars and maintained (if possible) during 2 years.
Inflow into the formation is controlled by Bottom
Hole Pressure (BHP). This is repeated for each type
of rock to compare solid saturation distributions.
The second example looks into the influence of
changing injection rates (pressures) on the solid
saturation
using
the
Viking
sandstone
characteristics. Finally, the third model compares
results obtained previously for the Viking sandstone
with results in which CO2 injection has been
preceeded by pure water injection.
Simulation Problem Set Up
The simulations presented herein illustrate CO2
injection into a highly saline aquifer, such as found
in the North German basin [10,11]. Total Dissolved
Solids (TDS) and brine density are 250 g/L and
1160 kg/m3, respectively. For this exercise, the
molar fractions (X) of NaCl and CaCl2 are XNaCl
=0.0859 and XCaCl2=1.1x10-3.
The simulations consist of injecting CO2 into a
radially symmetric reservoir section at a specified
rate that is controled by a maximum bottom hole
pressure (BHPmax) of 85 bars, to avoid pressure
rising above the reservoir fracturing pressure.
Injection continues through time unless it is
interrupted because the BHPmax has been reached.
This occurs whenever enough halite precipitation
has occurred to cause pressure to increase. In
practice, fracturing pressure would need to be
determined in the field and the mobility factor
curve in laboratory experiments in cores of the
reservoir. CO2 is injected at rates of approximately
1 kg/s (53 000 m3/day at surface conditions of
pressure and temperature) and 100,000 m3/day,
depending on the example.
The parameters of this model are listed in Table
1 and detailed below.
Model geometry. The numerical model
represents a 30 m thick cylindrical sandstone
section (Fig. 2). The top is horizontal at 730 m
depth. Reservoir temperature is 35°C. The radial
grid comprises grid-elements increasing in size
outwards. The smallest grid interval is 0.1 m at the
injection well and the largest is 10,000 m at the
outer boundary 10,250 m away (the number of cells
in the radial direction is 210). Vertical grid interval
is uniform and is 3 m. The injection well is
completed such that injection occurs in the lower 15
m of the domain.
Material properties. The reservoir rock has
homogeneous and isotropic properties. Porosity is
20%. Rock compressibility is 7.5.10-5 bar-1 at 75
bars. In the horizontal direction, the permeability is
200 mD (milidarcies), while in the vertical (z)
direction it is 66 mD. Relative permeability
measurements for CO2-brine systems are rare. We
utilize here 3 sets of experimental data from
literature [12,13]. These correspond to the
measurements made on sedimenary rocks of the
Alberta Basin in Canada. They are found under
conditions different (depth, pressure, temperature,
permeability) than those examined here. However,
they serve well to illustrate the large range in
behavior found as a function of relative
Model Results
Influence of relative permeability and capillary
pressure: Fig. 4 is a display of solid saturation
distribution for three different rocks 2 years after
injection began: (a) Basal Cambrian, (b) Viking and
(c) Ellerslie. It represents a pie shaped section of
the model. In the case of the Basal Cambrian
Sandstone, precipitation occurs rapidly and the well
has to be shut down because the maximum bottomhole pressure is reached within 14 days of injection
begin. In the other 2 settings, injection is not
impaired up to 50 years (end of calculation period,
equivalent to the lifetime of the injection operation)
even with some precipitation present.
If capillary pressure is set to zero, no
precipitation at all occurs in any setting.
These results suggest that these properties affect
strongly the amount and distribution of halite
scaling in the near wellbore zone. Laboratory
experiments [14] suggest capillary pressure
3
gradients drive precipitation at the dry-out front.
This implies that simplifying models by using zero
capillary pressure may produce wrong results.
As mentioned before, the mobility impact of
precipitation is chosen arbitrarily and the results are
a function of the implementation in the code. To
validate, specific laboratory experiments, such as
core flooding tests, are necessary. No operational
decisions can be taken on the basis of these models
alone.
Now we turn to investigating models that test
mitigation possibilites to address the negative
impact of precipitation in the near wellbore on CO2
storage operations: injection pressure and pretreatment with dilute solutions.
Influence of injection pressure. The same
problem discussed previously was run using
different injection rates. The results for 3 rates
(43,000, 53,000 and 63,000 m3/day) are shown in
Table 2.
Maximum precipitation occurs at the top of the
injection interval and in the nodes closest to the
well. As injection rate increases, therefore
increasing the pressure in that region, the maximum
solid saturation decreases from 80% to 26%. This
suggests, that increasing injection rates helps
mitigate the problem of scaling. It may be
problematic in very low permeability reservoirs as
injection pressure may attain fracturing pressure.
This behaviour also explains why no precipitation
is felt in project in high permeability sandstones,
where easily high injection rates can be imposed
[15].
Mitigation by diluting brine in the near
wellbore: one possibility of mitigating scale is by
avoiding it to occur by diluting the brine in the near
well bore area or filling it with low salinity fluid
before CO2 injection begins. This can be achieved
by injecting a dilute fluid, here we use pure water.
The results depicted in Fig 5 represent withwithout (pre-flush) pairs. In the first case (a), only
CO2 is injected during 2 years. In the second (b),
pure water is injected during one month and then
followed by 2 years of injecting CO2.
The pre-flush has diminished strongly the
amount and spatial spread of scale. Precipitation is
concentrated at the upper part of the injection
section, while precipitation occurs all along the
injection section when no pre-flush is performed.
This mitigation option is routinely applied in
gas storage operations at regular intervals [5].
Conclusions
When CO2 is injected in brine reservoirs, H2O is
continuously vaporized into the CO2 phase in the
near wellbore area. In high salinity environments
and low permeability, this dessication of the brine
leads to higher salinity, oversaturations and
ultimately salt precipitation diminishing the
porosity and very probably the permeability in this
region. This can lead to an interuption in operations.
Numerical simulations are helpful to assess this
risk to operations and test mitigation strategies.
Modeling results presented herein suggest:
•
Relative permeability and capillary pressure
are relevant for the amount and spatial
distribution of precipitation in reservoir
pores.
•
Increasing injection pressure may help
diminish the impact of precipitation on
fluid flow.
•
Preceeding CO2 operations with injection
of a dilute solution can prevent precipitation of affecting the storage project.
However, before application of these models,
the relationship between dry-out, salting-out,
pore
space
change
and
permeability
modification needs to be assessed in laboratory
experiments on cores of the reservoir of interest.
Literature
[1] Ennis-King, J. and Paterson, L.: Role of
convective mixing in the long-term storage of
carbon dioxide in deep saline formations, SPE
84344 prepared for presentation at the SPE Annual
Technical Conference and Exhibition held in
Denver, Colorado, U.S.A., 5-8 october, 2003, 12 pp.
[2] Nghiem, L., Sammon, P., Grabenstetter, J., and
Ohkuma, H.: Modeling CO2 storage in aquifers
with
a
fully-coupled
geochemical
EOS
compositional simulator, SPE 89474, prepared for
presentation at the 2004 SPe/DOE 14th Symposium
on Improved Oil Recovery held in Tulsa, Oklahoma,
U.S.A., 17-21 April 2004, 16 pp.
[3] Carpenter, A.B.:Origin and chemical evolution
of brines in sedimentary basins, SPE 7504 prepared
for presentation at the 53rd Annual SPE Technical
Conference held in Houston, Texas, 1-3 October
1978, 8 pp.
[4] Hurter, S., Labregere, D. and Berge, J., 2007.
Simulations for CO2 injection projects with compositional simulator, SPE 108540, prepared for
presentation at Offshore Europe 2007 Conference
4
systems, prepared for presentation at the 2006
SPE/DOE Symposium on Improved Oil Recovery
held in Tulsa, Oklahoma, U.S.A., 22-26 April, 10
pp.
held in Aberdeen, Scotland, U.K., 4-7 September,
2007, 8pp.
[5] Kleinitz, W., Koehler, M., and Dietzsch, G.:
The precipitation of salt in gas-producing wells,
SPE 68953 prepared for presentation at SPE
European Formation Damage Conference held in
The Hague, The Netherlands, 21-22 May 2001, 7
pp.
[14] Zuluaga, E., Munoz, N.I. and Obando, G.A.,
2001. An Experimental study to evaluate water
vaporisation and formation damage caused by dry
gas flow through porous media, SPE 68335,
presentation at the SPE International Symposium
on Oilfield Scale, Aberdeen, 30-31 January, 7 pp.
[6] Eclipse Technical Description 2006.1.,
Schlumberger Information Solutions software.
[15] Hansen A., Eiken, O., and Aasum. T.O.:
Tracing the path of carbon dioxide from a
gas/condensate reservoir, through an amine plant
and back into a subsurface aquifer – case study: the
Sleipner area, Norwegian North Sea, SPE 96742
prepared for presentation at the SPE Offshore
Europe 2005 held in Aberdeen, Scotland, U.K., 6-9
September 2005, 15 pp.
[7] Spycher, N., Pruess, K., and Ennis-King, J.:
CO2-H2O mixtures in the geological sequestration
of CO2. I. Assessment and calculation of mutual
solubilities from 12 to 100°C and up to 600 bar,
Geochim. et Cosmochim. Acta, (2003) 67, No. 16,
3015-3031.
[8] Spycher, N. and Pruess, K.: CO2-H2O mixtures
in the geological sequestration of CO2. II.
Partitioning in chloride brines at 12-100°C and up
to 600 bar, Geochim. et Cosmochim. Acta (2005),
69, No. 13, 3309-3320.
Acknowledgements
The authors thank colleagues of Schlumberger
Doll Research Center in Boston: T.S.
Ramakrishnan, B. Altundas and S. Verma.
[9] Nelson, P.H.: Permeability-porosity relationships in sedimentary rocks, The Log Analyst, (1994),
35, No.3, 38-62.
[10] Förster, A., Norden, B., Zinck-Jørgensen, K.,
Frykman, P., Kulenkampff, J. Spangenberg, E.,
Erzinger, J., Zimmer, M., Kopp, J., Borm, G.,
Juhlin, C., Cosma, C.-G., and Hurter, S.: Baseline
characterization of the CO2SINK geological
storage site at Ketzin, Germany, Environmental
Geoscie-ces (2006) 13, No. 3, 145-161.
[11] Magri, F., Bauer, U., Clausnitzer, V., Jahnke,
C., Diersch, H.-J., Fuhrmann, J., Moeller, P.,
Pekdeger, A., Tesmser, M. and Voigt, H.: Deep
reaching fluid flow close to convective instability in
the NE German basin – results from water
chemistry and numerical modelling, Tectonophysics
(2005), 397, 5-20.
[12] Bennion, B. and Bachu, S., 2005. Relative
permeability characteristics for supercritical CO2
displacing water in a variety of potential
sequestration zones in the Western Canada
Sedimentary Basin, SPE 95547, prepared for
presentation at the 2005 SPE Annual Technical
Conference and Exhibition held in Dallas, Texas,
U.S.A., 9-12 October, 15 pp.
[13] Bennion, B. and Bachu, S., 2006. The impact
of interfacial tension and pore size distribution /
capillary pressure character on CO2 relative
permeability at reservoir conditions in CO2-Brine
5
1.0
0.8
0.6
0.4
0.2
0.0
0
0.2
0.4
0.6
0.8
(a) Cambrian
Swirr = 0.3
0.8
Relative Permeability
Mobility Factor
1.0
0.6
0.4
0.2
0.0
0.0
1
0.2
0.4
0.6
0.8
1.0
Water Saturation
Solid Saturation
Relative Permeability
1.0
Figure 1. Model for the relationship of effect on
permeability of precipitation in the pores. Mobility
factor as a function of solid saturation (amount of
pore space occupied by precipitated salt). For
example, when solid saturation attains 0.4 (40% of
porosity), the intrinsic (absolute) permeability is
multiplied by 0.35. At a saturation of 0.8,
permeability is assumed to reduce to zero.
(b) Viking
Swirr = 0.55
0.8
0.6
0.4
0.2
0.0
0.0
0.2
0.6
0.8
1.0
Water Saturation
Injection Well
1.0
Relative Permeability
Radius=10 km
injection
interval, 15 m
0.4
30 m
(c) Ellerslie
Swirr = 0.65
0.8
0.6
0.4
0.2
0.0
0
0.2
0.4
0.6
0.8
1
Water Saturation
Figure. 2. Model geometry. Radial symmetric
domain with injection well in the centre. Injection
section is the lower half. See details in Table 1.
Figure 3. Relative permeability curves for 3
sandstones from the Alberta Basin in Canada: (a)
Cambrian, (b) Viking and (c) Ellerslie, respectively.
The graphs show relative permeability as a function
of water saturation, described by the continuous
curve. The dotted curve represents the
corresponding relative permeability for CO2.
6
(a) Cambrian
(b) Viking
0%
(c) Ellerslie
Solid Saturation
100%
Figure 4. Solid saturation after 2 years modeling time. In case (a) for the Basal Cambrian sandstone injection
ceased because precipitation attained 0.8 in most of the injection section. In the other 2 cases precipitation was
not enough to affect injectivity, although differences in precipiation distribution are noticed.
Table 1-Summary of Properties
without
pre-flush
0%
with
pre-flush
Solid Saturation
Property
Value
Radial grid interval increases away from injection well
Min. radial grid size (injection
0.1 cm
well)
Max. radial grid size (outer
10,000 m
edge)
Vertical grid size
3m
Depth of top of reservoir
730 m
Reservoir Thickness
30 m
Porosity
20%
Horizontal Permeability
200 md
Vertical Permeability
66 md
Brine Composition
8.59 x 10-2/1.1 x 10-3
NaCl/CaCl2 molar fraction
Brine salinity (TDS)
250 g/L
Brine density
1160 kg/m3
Initial pressure at 730 m
75 bar
Reservoir Temperature
35°C
Rock Compressibility (75 bar)
7.5x10-5 bar
Max BHP
85 bar
100%
Figure 5. Solid saturation for the Viking Sandstone.
Left: CO2 injection without pre-treatment (see Fig.
4). Right: 2 yrs of CO2 injection is preceeded by 1
month of pure water injection at the same rate.
7
Table 2. Maximum Precipitate vs Rate
Injection Rate
Max Solid Saturation
x 103 m3/day
43
0.80
53
0.39
63
0.26
8