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CCS in Japan

I2CNER - efforts to achieve effective,safe CO2 storage
The International Institute for Carbon-Neutral Energy Research (I2CNER) is studying CO2 behavior
from molecular to field scale to achieve better CO2 storage.
By Takeshi Tsuji, CO2 Storage Division, I2CNER, Kyushu University

CO2 storage division atI2CNER
At the CO2 Storage Division of I2CNER, wedevelop methods to characterize CO2 injection reservoirs to allow pre-injection site selection and post-injection predictions of thefate of CO2. We also monitor injected CO2
to help ensure safe and permanent CO2 sequestration.
To accomplish these goals, we are pursuingfundamental research to elucidate CO2 behavior over a wide range of scales (Figure 1).
In particular, we are studying the influence ofmolecular-scale (or pore-scale) characteristics
on field-scale CO2 behavior; i.e., determining the relationships between multi-scale
phenomena. For example, the wettability ofeach mineral calculated at the molecular scale
could influence the kilometer-scale CO2 behavior in a reservoir.
Here we report our recent work on the characterization of CO2 behavior from molecular
to field scale.

Figure 1. Injected CO2 behavior from the molecular scale to the field scale. We aim to understand therelationships between multi-scale phenomena

To do this, we calculated the reaction process
between supercritical CO2 and host rock(e.g., igneous rock), and showed how carbonate ions () are generated on the surface of thehost mineral (Figure 2). If suitable cations(e.g., Ca2+ or Mg2+) are present in the vicinity of , insoluble carbonate minerals will form.
These kinds of cations are abundant in igneous rocks like basalt.

Molecular to pore scale
Modeling of CO2 mineralization

We have also investigated fluid mixtures of
CO2 and hydrogen sulfide (H2S) by a similar

approach because H2S is a major concomitant geothermal gas of CO2. The overall costof CO2 capture and storage (CCS) could belowered substantially by injecting a mixture
rather than pure CO2.
This research provided microscopic insights
into geochemical trapping of CO2. Our
molecular dynamics simulations also revealed
interfacial properties, such as wettability, ofthe fluid mixtures.

Mineralization (i.e., geochemical CO2 trapping) is considered a safe way to store CO2.
This trapping mechanism converts CO2 to
insoluble minerals (e.g., CaCO3) via geochemical interactions with rock and formation water.
It was believed until recently that CO2 mineralization takes several hundreds to thousands of years. However, the Iceland-based
pilot project demonstrated that CO2 mineralization takes less than two years in basaltic
rock. We have revealed the microscopic
mechanism of mineralization through firstprinciples calculations (ab initio moleculardynamics simulations).

4Figure 2. Example of an ab initio molecular dynamics simulation of a supercritical CO2 reaction,
showing snapshots after (a) 0 fs (initial configuration), (b) 594 fs, and (c) 750 fs. The green frames in(b) and (c) indicate formation of ion

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Accurate porous flow
characterization by considering
slip flow at the fluid–solidinterface
Hydrological properties such as permeability
play a major role in determining the storage
capacity of a geological site. The typicallength scale of pores available in these sites isof the order of a few micrometers. At thissmall scale, the slip effect starts to appear at
the fluid–solid interface and affects the permeability of the rock.
We incorporated the slip effect into a lattice
Boltzmann simulation by using a diffusively
reflecting solid wall boundary condition. We
used a simple homogeneous porous medium
to validate that this boundary condition wascapable of reproducing the effect of slip (Figure 3a).
An increased slip velocity inside the porethroat was obtained upon using an appropriate diffusively reflecting boundary condition(right in Figure 3a) compared with that using
the conventional boundary condition (left inFigure 3a).
To evaluate the extent of the influence of slip
on bulk properties like permeability, we calculated the permeability with different Knudsen numbers (Kn). Kn is defined as the ratioof the molecular mean free path to characteristic macroscopic length, and is inversely related to pore size. The rise in slip velocity results in increased permeability with decreasing pore size (Figure 3b). This effect is generally not considered in conventional numericalmethods.

Pore to rock scale
Identifying suitable reservoir
conditions for effective, safe CO2storage
We have tried to identify suitable reservoir
conditions (e.g., pressure) for effective, safe
CO2 storage. The behavior and saturation of
CO2 in a reservoir is influenced by many
reservoir parameters, including the viscosityand density of the fluids, interfacial tension,pore structure, and other porous medium
characteristics like wettability and surface
roughness. Therefore, it is challenging toidentify suitable conditions for CO2 storage.
We calculated CO2 displacements in 3D natural sandstone under various conditions using
two-phase lattice Boltzmann simulations, andcharacterized the influence of reservoir condi-Figure 3. (a) Steady-state streamlines and fluid velocity using (left) a conventional boundary conditionand (right) our boundary condition considering slip. (b) Permeability correction factor (κ/κ0) withrespect to Knudsen number (Kn). The permeability predicted from our analysis agrees with analytical
onetions on CO2 and water flow (Figure 4a) [1].
The results of simulations conducted undermore than 50 combinations of conditions
were used to classify the resulting two-phaseflow behaviors into typical fluid displacement
patterns in plots of capillary number (Ca)against the viscosity ratio of CO2 to water(M). In addition, the saturation of the nonwetting phase (CO2) was calculated andmapped on the Ca–M diagrams.
In CCS, we should consider the domain of M
< 1 (the areas indicated by red rectangles inthe bottom panels of Figure 4). Our results
demonstrated that CO2 saturation is controlled by Ca and M, and the optimum CO2saturation scales with Ca and M (bottom ofFigure 4a).
Similar analysis of a different type of rock (2Dhomogeneous model in Figure 4b) revealed
that its CO2 saturation and behavior werequite different from those of 3D natural rock.

These important differences between twophase flow in 3D natural rock and the 2D homogeneous model could be caused by the heterogeneity of pore geometry and differencesin pore connectivity.
Our approach provides useful information todetermine suitable reservoir conditions for effective CO2 storage (e.g., high CO2 saturation) by quantifying CO2 behavior in a target
reservoir rock under various conditions (i.e.,saturation mapping on the Ca–M diagram).

Quantifying CO2 saturation inreservoirs from monitoring data
Time-lapse seismic surveys are suitable tomonitor CO2 distributions within reservoirs,
but it is difficult to quantify CO2 saturationfrom time-lapse seismic data. To estimate
CO2 saturation from seismic velocity, the relationship between CO2 saturation and seis-carbon capture journal - Nov - Dec 2016

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CCS in Japanmic velocity must be determined (Figure 5a).
However, this relationship is difficult toquantify because the response of seismic velocity to CO2 saturation is affected by multiple factors, and is also influenced by the CO2
distribution in the pore spaces of rock (seeFigure 4). Therefore, quantitative monitoring
requires both hydrological and geophysicalapproaches.
We evaluated the influence of CO2 behavior
within rock pores on the relationships between seismic velocity and CO2 saturation(Figure 5a) [2]. We conducted two computational studies with different injection pressures using (1) a two-phase lattice Boltzmann
method to simulate CO2 injection (i.e., hydrologic simulation) and (2) wave propagation simulation with a finite difference approach to evaluate seismic velocity (i.e., elasticsimulation).
We identified a difference in the relationships
between seismic velocity and CO2 saturation
in a few cases; i.e., lower seismic velocity wasobserved when Ca was high than when Ca
was low at the same saturation (Figure 5a).
The difference in velocity response to CO2saturation was controlled by CO2 distribution features. Ca (or the pressure gradient)
depends on the distance from the injection
well (Figure 5b). Low Ca values are expected
far from the injection well and high ones near
the well.
This study demonstrated that Ca at eachreservoir location should be considered to accurately estimate CO2 saturation from seismic monitoring data.

Figure 4. (a) 3D pore geometry of natural sandstone (top left), and CO2 behavior in 3D natural
sandstone under viscous fingering and capillary fingering regimes (top right). The bottom panel showsthe displacement pattern and CO2 saturation plotted on a diagram of capillary number Ca against
viscosity ratio M [1]. The dots indicate the calculation conditions. The color map on the phase diagramshows the CO2 saturation. (b) CO2 behavior in the 2D homogeneous pore model under differentconditions (top). The displacement pattern and CO2 saturation for the 2D homogeneous pore model areplotted on a diagram of Ca against M (bottom)

structure and attenuation coefficient (Figure6b and c, respectively).
From these results, we identified a geologicalboundary developed for northwest–southeastdirection. This was the first demonstration ofusing surface waves to identify a 3D S-wave
velocity distribution in a CO2 storage site.

Because the S-wave velocity reflects thestrength of a formation, the estimated S-wave
velocity distribution can be used to evaluate
lithology strength for geomechanical simulation (prevention of a CO2 injection-inducedearthquake).
The estimated heterogeneity also provides vital information for CO2 geological storage,

Rock to field scale
Reservoir characterization in highresolution (application to theTomakomai CCS project)
Geological heterogeneity influences CO2 behavior in reservoirs. In particular, if there are
localized fractures in CO2 storage sites, they
may behave as CO2 leakage paths. To detect
localized heterogeneity in high resolution(i.e., downscaling), we developed an advanced
seismic processing method using surface
waves [3].
Our method allowed us to characterize local
heterogeneity by integrating S-wave velocity
and attenuation. We applied the method to
3D seismic data acquired at the Tomakomai
CO2 storage site, Japan, and successfully extracted a high-resolution S-wave velocity

6Figure 5. (a) Relationship between seismic velocity and CO2 saturation at different capillary numbers
Ca [2]. These relationships were calculated by lattice Boltzmann method fluid flow simulations anddynamic wave propagation simulations. Circles indicate the results for higher Ca and diamonds those forlower Ca. Red asterisks show results for randomly distributed models. (b) Injected CO2 behavior under
different reservoir conditions (Ca)carbon capture journal - Nov - Dec 2016

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CCS in Japansuch as evaluation of CO2 leakage paths andpermeability heterogeneity used in reservoir
simulation.

Continuous, accurate monitoring
system for injected CO2
In CCS, monitoring of injected CO2 is crucial to (a) predict the risk of CO2 leakage
from storage reservoirs, (b) increase the efficiency of CO2 injection and lower its cost,and (c) lower the risk of injection-inducedseismicity.
Time-lapse seismic surveys have been used tomonitor the distribution and migration of injected CO2. However, the monitoring interval in time-lapse surveys is usually long because of the high cost of monitoring; it is generally too expensive to continuously monitor
the injected CO2. However, continuous
monitoring of dynamic CO2 behavior is crucial to detect incidents associated with CO2
injection (e.g., leakage).
We developed a seismic monitoring systemusing a continuous, controlled seismic source(Figure 7a) [4]. Our system monitored theshallow subsurface through temporal variation of surface-wave velocity.
Compared with conventional monitoring, oursystem is cost-effective with high temporal
resolution and accuracy. Field experiments
showed that hourly variation of surface-wave
velocity could be monitored with better than
1% accuracy (Figure 7b).

Figure 6. (a) The estimated 3D S-wave velocity model for the Tomakomai CO2 storage site.
Horizontal slices (map views) of the estimated (b) surface-wave velocity and (c) attenuation ~50 m
below the seafloor [3]This temporal stability provides the possibility to detect changes in seismic velocities associated with CO2 leakage through fault zones.
Recently, we used this monitoring system in
the Aquistore CCS project in Canada, andclearly identified seasonal variation associatedwith the degree of freezing in shallow sediments.

References[1] Tsuji, T., Jiang, F., Christensen, K.
(2016), Advances in Water Resources, 95, 315.
[2] Yamabe, H., Tsuji, T., Liang, Y., Matsuoka, T. (2015), Int. J. Greenhouse Gas
Control, 46, 197-204.
[3] Ikeda, T., and Tsuji, T. (2015), Int. J.
Greenhouse Gas Control, 39, 107-118.
[4] Ikeda, T., Tsuji, T., Watanabe, T., Yamaoka, K. (2016), Int. J. Greenhouse Gas
Control, 45, 94-105.

Figure 7. (a) Continuous seismic monitoring of injected CO2 and detection of leaked CO2. The
photograph shows the monitoring device, which generates a continuous, accurate source signal. (b)Hourly variation of (upper) surface-wave velocity, (middle) velocity change for averaged velocities, and(lower) sensitive depth in field experiments [4]8carbon capture journal - Nov - Dec 2016

More information
i2cner.kyushu-u.ac.jp/en