**GEO-SEQ Quarterly Report: October 1, 2005 to December 31, 2005**

Earth Sciences Division

Lawrence Berkeley National Laboratory

Berkeley, California 94720

Contact: Dr. Sally M. Benson

Earth Sciences Division

Lawrence Berkeley National Laboratory

1 Cyclotron Rd., MS 90-1116

510-486-5875; <smbenson@lbl.gov>

DOE Program Manager: Karen Cohen, 412-386-6667

**Highlights**

-   Mapping migration of CO~2~ using X-well seismic and Vertical Seismic
    Profiling (VSP) in a saline formation has been demonstrated for the
    first time at the Frio Brine Pilot.

-   A new method for measuring field-scale relative permeability from
    pressure transient test data has been developed.

-   Five papers describing the Frio Brine Pilot were presented at the
    AGU Annual Meeting in December 2005. This completes the FY06 QTR1
    Milestone.

-   Planning for Phase II of the Frio Brine Formation Pilot Tests has
    begun.

-   Collaboration between LBNL and CO2CRC for the Otway project has
    begun. Several meetings and discussion have taken place in order to
    define current workscopes between groups.

**Project Milestones**

+-----------------------------------+-----------------------------------+
| **Task**                          | **Deliverable Date**              |
+-----------------------------------+-----------------------------------+
| QTR 1                             | December 30, 2005 - Complete      |
|                                   |                                   |
| Submit abstract to the Fall 2005  |                                   |
| AGU meeting on Frio Formation     |                                   |
| CO~2~ Injection Studies.          |                                   |
|                                   |                                   |
| -   Five abstracts were submitted |                                   |
|     and accepted for              |                                   |
|     presentations and posters.    |                                   |
|                                   |                                   |
| -   Abstracts are attached to     |                                   |
|     this report.                  |                                   |
+-----------------------------------+-----------------------------------+
| QTR 2                             | March 30, 2006                    |
|                                   |                                   |
| Design of geophysical monitoring  |                                   |
| and fluid sampling for Frio II.   |                                   |
+-----------------------------------+-----------------------------------+
| QTR 3                             | June 30, 2006                     |
|                                   |                                   |
| Submit abstract(s) to the 5th     |                                   |
| Annual National Carbon            |                                   |
| Sequestration Conference held in  |                                   |
| May, 2006 in Alexandria,Virginia. |                                   |
+-----------------------------------+-----------------------------------+
| QTR 4                             | September 30, 2006                |
|                                   |                                   |
| Initiate data collection for the  |                                   |
| Frio II Pilot Test.               |                                   |
+-----------------------------------+-----------------------------------+

**Research Progress Report**

**Task 1. Phase II for the Frio Brine Formation Pilot Tests.**

To prepare for the Frio II Pilot test, detailed simulations of CO~2~
transport will be carried out based on the results obtained from the
Frio Brine Pilot Test conducted in FY2004. This work will take advantage
of new insights on multiphase flow, solubility trapping and mineral
trapping that were gained from the short-term pilot test conducted
during FY2004. The numerical simulators TOUGH2 and TOUGHREACT will be
used for these studies.

More reliable estimates for the amount of CO~2~ that can be stored per
unit volume of the Frio Formation will be developed based on what we now
know about field-scale relative permeability and CO~2~ pore volume
occupancy. Field-derived values for these parameters will be used as
input to the TOUGH2 simulator and combined with realistic geology to
perform numerical simulations of CO~2~ storage capacity for the Frio. As
a second part of the planning study, the amount of CO~2~ that can be
stored by solubility and mineral trapping will be assessed using
TOUGHREACT. Again, improved understanding and estimates will be based on
geochemical data obtained from the Frio Brine Pilot I. Specifically, we
will use mineralogical data obtained from cores collected during
drilling the new injection well at the test site and water samples
collected during the CO~2~ injection, which provided new data on CO~2~,
brine and formation interactions.

Field testing for Phase II of the CO~2~ injection test at the Frio Test
Site will be carried out in cooperation with the Texas Bureau of
Economic Geology. The goals of the experiment are designed to answer
extremely important questions not addressed during the first experiment.
Specifically, to what extent do gravitational forces drive upward
migration of the plume? How much CO~2~ remains trapped as a residual
phase? How much CO~2~ dissolves in the brine as it migrates upward under
buoyancy forces? Where does the displaced water go? To the extent
possible, the experiment will take advantage of baseline data collected
as part of the first test.

For this test, CO~2~ will be injected into a deeper part of the C sand.
After injecting a small amount of CO~2~ (the precise volume will be
determined by modeling studies), migration of the plume will be tracked
for a period of up to a year or more, allowing observations of the
extent to which gravitational forces drive the plume upwards and the
extent to which the CO~2~ remains trapped a residual phase. A
combination of well logs, and geophysical imaging will be used to track
migration of the CO~2~. Fluid samples will be collected to determine the
extent of CO~2~ dissolution in the brine. In addition, fluid sampling
will be used to track migration of the displaced water. The role of our
team will be to:

-   Continue to refine interpretation of the Frio I test data to improve
    the knowledge gained from this test and to improve MMV methods;

-   Help identify the optimal suite of MMV technologies to deploy by
    using our forward and inverse geophysical simulator;

-   Deploy unique capabilities such as the U-tube sampler, multi-level
    sampler, noble gas tracers, and potentially, the P- and S- wave
    seismic source; and

-   Participate in the integrated interpretation and simulation of the
    fate and transport of the injected CO~2~.

***Task 1 Results and Discussion***

**[Geophysics]{.underline}**

Data analysis of the Frio site crosswell and VSP data has continued.
Analysis of the VSP data was refined with more accurate spatial mapping
of the observed CO~2~ induced changes. These changes, mapped on three
azimuths from the injection well, compared favorably to the expected
CO~2~ saturation predicted by flow models. Analysis of the crosswell
amplitudes has begun, including initial finite-difference modeling.
Initial estimates of partial CO~2~ saturation derived from field
measurement of velocity changes were accomplished. Analysis of ambient
borehole seismic \'noise\' using the time-lapse crosswell data shows
potential for monitoring changes in fluid motion in the borehole
annulus. Collaboration on analysis of the VSP data was begun with
Schlumberger. Collaboration on analysis of the crosswell data was begun
with MIT. Results were presented at the annual meetings of the Society
of Exploration Geophysicists, and the American Geophysical Union.
Additionally, initial planning for the second Frio injection experiment
has begun. A more detailed discussion on the use of seismic noise for
locating flow behind the casing is presented below.

*Seismic Noise Analysis from the Cross-well Data Collected at the Frio
Brine Pilot*

Acoustic noise studies in wells for the purpose of characterizing out-of
the casing fluid flow was a subject of intensive studies in the past.
The results suggested possibility of multi-fluid flow detection and
recognition using noise spectra in 0-5 KHz range. Although the noise
studies were not initially planned for the CO~2~ injection experiment,
we later included noise analysis as it seemingly contained interesting
information. Noise records were obtained by extracting the 0.25-0.4 s
interval from the 0.5 s long traces to avoid influence of source related
direct body waves. Figure 1 shows an example of pre- and post- shot
gathers for 5000 ft source depth. Visible are increased noise at
5030-5060 ft (injection) and 4950-5000 ft depth intervals in
post-injection gather. These high noise depth ranges are present at all
source gathers which means that they are not related to any specific
source position. However, a substantial part of the noise might be
caused by the seismic source because of multiple scattering of wave
energy in the formation and because converted tube waves generally have
low attenuation.

Noise amplitude spectra (Figure 2) show visible amplitude peaks at 80 Hz
and at 380 Hz. The 380 Hz peak is stronger than 80 Hz peak for
pre-injection data while this relationship reverses for the post- data.
This might be because of higher attenuation of the primary body waves in
gas saturated rocks. While there is no other significant depth related
features for source gathers (although there is some increase in
amplitudes at 188-170 Hz for 4940-4990 ft interval), there is a
distinctive change for injection well (5030-5060 ft interval) level and
for 4950-4990 ft interval. These indicate that the location of the
source noise is likely close to the injection (receiver) borehole. At
high frequencies (350 Hz) post injection amplitudes are about three
times lower than pre- injection amplitudes for all depths (Figure 3). At
lower frequencies the average noise levels for post- and pre- injection
amplitudes are comparable. Combined plots of all source-receiver pairs
(Figure 4) show two distinctive peaks of noise amplitudes for injection
(5030-5060 ft) interval and for 4950-4990 ft interval and confirm that
high noise sources are located close to the injection (receiver)
borehole.

In a search for phase flow signatures the noise amplitudes were computed
along the injection (receiver) well at different frequencies (Figure 4).
Amplitude dependence on frequency for the 4950-4990 ft interval shows
steady decrease as frequency becomes higher corresponding to two-phase
flow pattern. The amplitude distribution for the injection interval
shows highest peak at intermediate frequencies possibly indicating
presence of both one-phase and two phase flows. This interpretation can
be more conclusive if we had higher frequencies in data (at least up to
2 KHz). Currently, traces have frequencies up to 420 Hz.

Seismic noise in fluid-filled boreholes is primarily represented by
vertically propagating tube waves. Tube waves have low attenuation and
their velocities are usually below 1500 m/s. To evaluate the local
apparent velocities of the noise-forming waves we computed
cross-correlations of neighboring noise traces (Figure 5). The result of
such computation gives local measurements of (tube) wave velocities,
which are sensitive to rock properties behind the casing and to a
quality of casing contact with rock formation. For a homogeneous media
these plots would have distinct vertical stripe pattern. Deviations from
this pattern indicate changes in the well casing surrounding. The
largest distortions are observed at 5000 ft depth zone. Although the
dependence of the obtained images on depth turned out to be rather
complex, the shape of the cross-correlation curves seems to be rather
sensitive to the noise source. Figure 6 shows a correlation coefficient
between cross-correlation curve at reference depth of 4500 ft and
cross-correlation curves from Figure 5 computed for other depths.
Deviation of these curves from value one indicates that at this depth
the acoustic noise has components other than tube waves, which means
that the peaks point on the actual depths where the noise is generated.
Remarkably the pre-injection curve gives the largest peak at 4950 ft
[before the injection]{.underline}, possibly indicating a presence of a
faulty bonding between casing and the formation. This curve also points
at" the injection (reservoir) 5050 ft. If proven robust such
measurements can give locations of weak zones behind a casing before the
injection stage.

The results of the Frio CO~2~ seismic noise study suggest the presence
of the two-phase flow at 4950 ft depth (approximately 80 ft above the
reservoir) after the injection. This hypothesis will be tested by
evaluating pre-and post-injection well logs, and perhaps, by collecting
new data specifically for this purpose.

**(a)**

![](media/image1.png){width="4.875in" height="2.6805555555555554in"}

**(b)**

![](media/image2.png){width="4.875in" height="2.73125in"}

**Figure 1**. Seismic cross-well pre- (a) and post- (b) shot gathers for
5000 ft source depth for Frio CO~2~ injection experiment. Visible are
increased noise at 5030-5060 ft (injection) and 4950-5000 ft depth
intervals in post-injection gather.

![](media/image3.pct){width="2.2423611111111112in"
height="3.0243055555555554in"}**(a)**

![](media/image4.pct){width="3.125in"
height="2.7583333333333333in"}**(b)**

**Figure 2**. Noise amplitude spectra vs. source depth (a) and receiver
depth (b) for pre- and post-injection. Visible are amplitude peaks at 80
Hz and at 380 Hz. The 380 Hz peak is stronger than 80 Hz peak for pre-
data while this relationship reverses for the post- data. While there is
no other significant depth related features for source gathers (note
some increase in amplitudes at 188-170 Hz for 4940-4990 ft interval),
there is a distinctive change for injection (5030-5060 ft interval)
level and for 4950-4990 ft interval. These results indicate the location
of source noise in the close proximity of injection (receiver) borehole.

![](media/image5.pct)

**(a)**

**(b)**

**(c)**

**Figure 3**. Noise amplitude spectra vs receiver depth for pre- (blue
line) and post- (red line) injection at 170 Hz (a), 350 Hz (b), and 75
Hz (c). Reservoir level (5030-5060 ft interval) is clearly marked by a
sharp peak at 170 Hz. In the 4940-4990 ft interval has clear peaks at
all frequencies. At high frequencies (350 Hz) post injection amplitudes
are about three times lower than pre- injection amplitudes for all
depths. At lower frequencies the average noise levels for post- and pre-
injection amplitudes are comparable.

![](media/image6.pct){width="2.375in" height="2.5in"}

**(a) (b)**

![](media/image11.pct){width="2.4680555555555554in"
height="2.6909722222222223in"}

**(c) (d)**

**Figure 4.** Combined plots of cross-well Frio CO~2~ injection data for
all source-receiver pairs. Panels (a) and (b) show pre-injection
results, while panels (c) and (d) show post-injection results. Left
panels correspond to the data assembled along the receiver depths, and
right panels show the data assembled along the source depths. Small
black dots are the slownesses picks for the first arriving P- wave. Red
dots show amplitudes of the first arriving P-waves. Black crosses show
noise amplitudes for the whole spectral range. Blue dots ate the average
values of noise amplitudes. Distinctive are two-fold rises of noise
amplitudes for injection (5030-5060 ft) interval and for 4950-4990 ft
interval. These results similar to Figure 2 indicate the location of
source noise in the close proximity of injection (receiver) borehole.

![](media/image16.pct)

**Figure 5.** Noise amplitudes along the injection (receiver) well at
different frequencies for pre- (bottom panels) and post- (upper panels)
injection surveys. Set of frequencies includes: 75 Hz (blue lines), 100
Hz (red lines), 150 Hz (green lines), 300 Hz (violet lines), 400 Hz
(black lines). Left panels show whole range (4500-5500 ft) of receiver
depths, while right panels show same data for 4900-5100 ft depth
interval. Amplitude peaks on upper (post-) panels correspond to the
injection (5030-5060 ft) interval and to the 4950-4990 ft interval.
Amplitude dependence on frequency for this interval shows steady
decrease as frequency becomes higher corresponding to two-phase flow
pattern. The amplitude distribution for the injection interval shows
highest peak at intermediate frequencies possibly indicating presence of
both one-phase and two phase flows. This interpretation can be more
conclusive if we had higher frequencies in data (at least up to 2 KHz).
Currently, traces have frequencies up to 420 Hz.

![](media/image18.pct){width="4.25in" height="2.8777777777777778in"}

**Pre- Post-**

**Figure 6.** Cross-correlation of neighboring noise traces
(velocitygramm) for pre-injection (a) and post- injection (b) data.
Horizontal axis is scaled to have slowness units 10^5^ s/m. Closest to
zero slowness maximums correspond to tube wave velocities. Other
maximums are likely the result of aliasing because of sparse vertical
receiver spacing. These plots give local measurements of tube wave
velocities, which are sensitive to rock properties behind the casing and
a quality of casing contact with rock formation. For a homogeneous media
these plots would have distinct vertical stripe pattern. Deviations from
this pattern indicate changes in the well casing surrounding. The
largest distortions are observed at 5000 ft depth zone.

![](media/image19.pct)

![](media/image20.pct){width="4.125in" height="3.6597222222222223in"}

**Figure 7*.*** *Left panel.* Correlation coefficient between
cross-correlation curve at reference depth of 4500 ft and
cross-correlation curves from Figure 5 computed for other depths. Blue
line shows pre- data and red line shows post- data. Deviation of these
curves from value one indicates that at this depth the acoustic noise
has components other than tube waves. In other words the peaks on this
figure point on the actual depths where the noise is generated.
Remarkably the blue (pre-) curve gives the largest peak at 4950 ft
[before the injection]{.underline}, possibly indicating a presence of a
faulty bonding between casing and the formation. This curve also points
at" the injection (reservoir) 5050 ft. If proven robust such
measurements can give locations of weak zones behind a casing before the
injection stage.

*Right panel.* Explanation of correlation anomaly caused by a local
noise source. Body waves enter into the well space a variety of incident
angle in a close proximity to the source. At some short distances from
the source they convert into tube waves propagating along the well.

**[Modeling studies in conjunction with the Frio brine
pilot]{.underline}**

Numerical modeling of the flow behavior of supercritical carbon dioxide
(CO~2~) injected into a brine-bearing sandstone was an integral part of
the Frio brine pilot for CO~2~ sequestration. Modeling was used to help
design the pilot and to improve understanding of multi-phase and
multi-component flow processes involved in geologic CO~2~ sequestration.
During the design phase, modeling was used to determine which of several
layers to inject into, how far apart injection and observation wells
should be (in particular showing that existing wells were too far apart,
necessitating the drilling of a new injection well), how much CO~2~ to
inject, and at what rate. Modeling of pre-injection,
site-characterization pump and tracer tests helped design these tests to
optimize the information gained on formation flow properties, in situ
phase conditions, and boundary conditions. As site-characterization
proceeded, the model was modified to incorporate new information. CO~2~
injection was simulated prior to the actual pilot, to assess the model's
predictive ability. Further model improvements were added subsequently,
based on detailed comparisons to the observed subsurface CO~2~
distribution.

Modeling illustrated the complex interplay between phase interference
and buoyancy flow that occurs as CO~2~ is injected into a
high-permeability, steeply dipping sand layer. By running simulations
with a range of parameters and comparing model results to field data we
improved our understanding of these flow processes. Generally good
agreement between observed and modeled CO~2~ spatial distributions and
travel times between injection and observation wells validated our
ability to model CO~2~ injection, while discrepancies pointed out areas
where future research is needed. The iterative sequence of model
development, application, and refinement proved useful for getting early
results in a timely manner as well as incorporating more complexities at
later stages. This work has demonstrated that we have an effective
modeling capability for representing the physical processes occurring
during CO~2~ sequestration in brine-bearing sandstones, and moreover
that the incorporation of modeling into geologic CO~2~ sequestration
activities is beneficial from the earliest design stages through the
final interpretation of field data.

*Comparison of ECO2 with ECO2N*

The majority of the Frio brine pilot modeling studies employ the TOUGH2
equation of state package ECO2, which has been in use for several years.
A new, more comprehensive equation of state package, denoted ECO2N, has
recently been developed, superceding ECO2 as the standard equation of
state package for modeling CO~2~ in saline aquifers. Comparison of
results obtained using ECO2 and ECO2N show only minor differences in the
formation and evolution of CO~2~ plumes for the conditions of the Frio
brine pilot.

*Analysis of the Effects of Hysteretic Characteristic Curves on
Interpretation of the Frio Brine Pilot*

TOUGH2 has had the capability of using hysteretic relative permeability
and capillary pressure curves for many years. Hysteretic capillary
pressure functions were introduced in the late 1980's and hysteretic
relative permeability functions were added about ten years later. Until
recently, however, the hysteretic version of TOUGH2 has not been
numerically efficient enough to be used for 2D or 3D CO~2~ sequestration
problems. Recent modifications have improved the numerics, making it
computationally competitive with non-hysteretic simulations.

The use of hysteretic characteristic curves is not so critical for the
simulation of CO~2~ injection periods when the plume is continuously
growing, because the entire model is following the primary drainage
branch of the capillary pressure curve, and this branch can be
replicated using a non-hysteretic formulation. However, for
post-injection periods, as the plume moves upward and updip due to
buoyancy forces, different locations experience drainage and wetting at
different times, necessitating the use of a hysteretic formulation.

New simulations have been done to evaluate the effect of hysteretic
characteristic curves on the pilot test have been carried out.

*Comparison of Frio I Simulations with Observed Data*

Figure 8 shows several views of the three-dimensional grid used for the
Frio I modeling studies. The grid is created as a stack of 13 flat
layers, then tilted to account for dip. Vertical grid spacing is chosen
to resolve geological variability in the upper part of the C sand, as
observed in well logs (Figure 9). Lateral grid spacing is finest near
the two wells, and gets coarser farther away.

![](media/image21.png){width="4.5in" height="4.115972222222222in"}

**Figure 8.** Three-dimensional grid used for modeling the Frio I brine
pilot.

![](media/image22.jpeg){width="4.940277777777778in" height="3.45in"}

**Figure 9**. Porosity and permeability profiles inferred from
injection-well logs and core sample analysis, and grid-averaged values
used for the model. The perforated interval is also shown. Geologic
variability is not resolved below the thin low-permeability marker bed
(shown with gray shading).

During the Frio I pilot (October 2004), sampling from the U-tube
indicated that free-phase CO~2~ arrived at the observation well 51 hours
(2.1 days) after injection began, somewhat earlier than the model
prediction of 3 days, made with the non-hysteretic TOUGH2 prior to the
field test (Figure 10). Subsequent modeling using the hysteretic TOUGH2
produced a CO~2~ arrival at 2.2 days. The hysteretic formulation uses a
zero value of residual gas saturation for drainage, the dominant process
occurring during the 10-day CO~2~ injection period, whereas the
non-hysteretic formulation used a small but non-zero value, resulting in
a greater mobility of the gas phase for the hysteretic case, which
enables more gravity override, and hence a shorter travel time from the
injection well to the observation well.

![](media/image23.png){width="4.75in" height="2.9in"}

**Figure 10**. Observed and modeled CO~2~ arrival at the observation
well. The pre-test model is non-hysteretic whereas the post-test model
uses a hysteretic formulation for characteristic curves.

Schlumberger's RST tool was used to produce CO~2~ saturation profiles at
the injection well and observation well at a series of times during and
after the Frio I CO~2~ injection, as shown in Figure 11. Model results
at the injection well compare favorably with the RST profiles, whereas
model results at the observation well show a CO~2~ plume that is about
one meter too low. Figure 11 shows that the upper limit of the CO~2~
plume in both wells is aligned with the upper limit of significant
porosity (right-hand panel). In the injection well, the model reproduces
this part of the actual porosity profile nicely, whereas in the
observation well the modeled top of the high-porosity interval is about
one meter too low. This finding suggests that either the Frio formation
dips more steeply than the assumed 16 degrees, or that the upper
boundary of the C sand is not a sharp, continuous low-permeability
layer. The latter assumption was tested by replacing part of the 0.61-m
thick, low-permeability layer above the injection interval with a
high-permeability sand, with the sand extending laterally from about
midway between the injection and observation wells to beyond the
observation well. This modification produced the desired upward shift in
CO­~2~ arrival at the observation well, without altering the CO~2~
distribution at the injection well.

Figure 11 also shows that the extent of the CO~2~ plume below the
perforated interval in the injection well is slightly greater than that
predicted by the model, suggesting that the thin marker bed located
below the perforated interval may not have as low a permeability as
assumed. These model modifications based on the CO~2~ distribution
illustrate the iterative nature of model development and application.
The strong preferential flow exhibited by the low-viscosity, low-density
CO~2~ plume provides a powerful tool for site characterization.

![](media/image24.jpeg){width="4.269444444444445in"
height="3.776388888888889in"}![](media/image25.png){width="5.236111111111111in"
height="4.066666666666666in"}

**Figure 11**. Observed and modeled CO~2~ saturation profiles in the
injection well (top) and observation well (bottom). At the perforated
interval in the injection well, day 66 and day 142 RST data cannot be
processed, due to operational changes made to the well at the end of
injection period. The right-hand panel shows porosity inferred from the
well log's Vshale (gray shading) and grid-averaged values (black lines).

Figure 12 compares the difference tomogram obtained from two crosswell
seismic surveys conducted prior to and about six weeks after the Frio I
injection of CO~2~ with model results for the CO~2~ distribution along
the vertical cross-section between the injection and observation wells.
We do not have a quantitative relationship between velocity change and
CO~2~ saturation, but there is excellent qualitative agreement between
the model and the tomogram for the CO~2~ distribution in the inter-well
plane.

![](media/image26.jpeg){width="3.609722222222222in"
height="3.55in"}![](media/image27.png){width="2.279861111111111in"
height="2.3381944444444445in"}

**Figure 12**. Velocity difference tomogram with saturation profiles in
the wells obtained from RST (left) and modeled CO~2~ distribution
(right).

Figure 13 compares vertical seismic profile (VSP) results for the far
field CO~2~ distribution about six weeks after the Frio I pilot with
model results. As for the crosswell seismic, we do not have a
quantitative relationship between VSP change in amplitude and CO~2~
saturation, so the vertical axes of the plot are adjusted to align these
two quantities close to the injection well. Figure 11 shows good
agreement between model and VSP in the updip direction (N), but the VSP
indicates that the plume has moved farther than the model has predicted
to the NE and NW. In fact, the plume has moved as far to the NW as it
has to the N, suggesting that either our notion of the true dip
direction is inaccurate, or that there is significant heterogeneity or
anisotropy in the permeability distribution beyond the immediate
vicinity of the wells. The non-smooth nature of the model profiles far
from the injection well indicates the need for a more refined grid.

![](media/image28.png){width="5.991666666666666in"
height="3.9993055555555554in"}

**Figure 13**. Comparison of VSP and model results for far-field CO~2~
distribution.

*Scoping studies for Frio II*

Frio II, the second stage of the Frio brine pilot, is in the preliminary
design stage. The goal is to inject a small plume of CO~2~ in a location
where it can move upward under buoyancy flow. Two locations are being
considered: the lower part of the C sand (below the thin
low-permeability marker bed, see Figure 9) and a deeper sand known as
the 5400 sand. Figure 9 indicates that unlike the upper C, where there
is a 5-m thick layer of very high permeability (\>2000 md) sand, in the
lower C, thin high- and low-permeability layers alternate. Hence,
buoyancy flow is expected to be less pronounced.

Table 1 summarizes the issues addressed by the first round of scoping
studies to aid in the design of Frio II. The model used for the studies
is similar to the one used for Frio I (Figure 8) except that 22 layers
are used in order to resolve geologic layering throughout the C sand and
lateral grid resolution is not as good (about 5 m grid spacing near the
wells). Because calibrated porosity and permeability profiles are not
available for the 5400 sand, the C sand model is used for these studies
as well, but with pressures and temperatures increased as appropriate
for the greater depth. Thus at this preliminary stage, the only issue to
be tested for the 5400 sand is how the pressure- and
temperature-dependent properties (density and viscosity of CO~2~ and
brine) affect the plume formation and evolution.

**Table 1**. Issues considered for preliminary scoping studies for Frio
II.

+-----------------------+-----------------------+-----------------------+
| **Issue**             | **Options**           | **Comments**          |
+-----------------------+-----------------------+-----------------------+
| Depth to inject       | Lower C sand          | Pro: geology already  |
|                       |                       | characterized via     |
|                       |                       | well logs calibrated  |
|                       |                       | to core samples.      |
|                       |                       |                       |
|                       |                       | Con: new plume might  |
|                       |                       | interfere with        |
|                       |                       | existing plume        |
|                       |                       | (injected in upper C  |
|                       |                       | sand).                |
+-----------------------+-----------------------+-----------------------+
|                       | 5400 sand             | Pro: no existing      |
|                       |                       | CO~2~.                |
|                       |                       |                       |
|                       |                       | Con: well-logs not    |
|                       |                       | yet calibrated to     |
|                       |                       | core samples.         |
+-----------------------+-----------------------+-----------------------+
| Rate to inject        | Same as Frio I (\~160 | Want slower arrival.  |
|                       | T/day) or less        |                       |
|                       |                       | Rate may be limited   |
|                       |                       | by pressure increase  |
|                       |                       | (if permeability of   |
|                       |                       | 5400 sand is much     |
|                       |                       | lower than C sand).   |
+-----------------------+-----------------------+-----------------------+
| Volume to inject      | 800 T or less         | Ideally would like    |
|                       |                       | arrival reasonably    |
|                       |                       | soon after injection  |
|                       |                       | is stopped. Limited   |
|                       |                       | by high cost of       |
|                       |                       | CO~2~.                |
+-----------------------+-----------------------+-----------------------+
| Time duration of      | 10 days or less       | Limited by high cost  |
| injection             |                       | of field time.        |
+-----------------------+-----------------------+-----------------------+

During Frio I, CO~2~ arrived at the observation well during the
injection period, when plume evolution was dominated by forced
convection. For Frio II, we would like to inject a small enough volume
so that arrival does not occur until after injection has ended, so we
will be monitoring a period of natural convection. The risk of CO~2~ not
reaching the monitoring well is much greater in this case however,
because as soon as injection ends, the problem shifts from a
drainage-dominated problem (plume continuously growing), to a problem
combining drainage (at the leading edge of the plume) and wetting (at
the trailing edge of the plume). For the wetting process, the residual
gas saturation can be quite large, effectively immobilizing the plume.

Tables 2 and 3 summarize the scoping simulations completed so far. Each
lower C sand simulation begins with the Frio I simulation (October
2004), then rests until March 1, 2006, which provides the initial
conditions for the Frio II simulation.

**Table 2**. Preliminary scoping calculations for Frio II.

  ---------- --------------------------- --------------------------------
  Case       Features                    Comments

  G05        Same rate and duration as   CO~2~ arrival 2.67 days --
             Frio I (\~1600 T in 10      comparable to Frio I
             days), inject at bottom 1.4 
             m of C sand                 

  G05-5400   Like G05, but at 5400'      CO~2~ arrival 2.73 days --
             depth                       nearly unchanged from G05

  G05A       Like G05, but half          CO~2­~ arrival at 4.5 days --
             injection rate              halving injection rate increases
                                         but does not double arrival time

  G05B       Like G05A, but spread       CO~2~ arrival at 5.7 days
             injection over lower 3 m of --longer arrival time for
             C sand                      thicker plume

  H05A       Like G05A, but all layers   CO~2~ arrival at 3.5 days
             more anisotropic:           --shorter arrival time for less
             k~v~/k~h~=0.1               buoyancy flow
  ---------- --------------------------- --------------------------------

Based on the results shown in Table 2, and the goal to slow down the
CO~2~ arrival at the observation well, a lower injection rate will be
advantageous. The pressure and temperature increase for the 5400 sand
increase CO~2~ density and viscosity just slightly, so have little
effect on CO~2~ plume evolution. Using a thicker injection interval and
considering a more anisotropic medium have modest effects.

The key question is the total amount of CO~2~ to inject, or
equivalently, the duration of the injection period, which will determine
whether injection is still occurring when CO~2~ arrives at the
observation well. Results of 20-day simulations using three different
injection periods are shown in Table 3. Another parameter varied for the
calculations is the value of maximum residual gas saturation S~grmax~.
Values from the Gulf Coast petroleum literature indicate that S~grmax~
\~ 0.2 for the multi-Darcy layers of the C sand, but our only
site-specific information on this parameter comes from the late-time RST
profiles (Figure 11). For the most, these profiles support large values
of S~grmax~, but in some instances smaller values are suggested.
Additionally, operational issues involving well reworking at the end of
the injection period made RST data difficult to interpret unambiguously.
Because S~grmax~ plays such a large role in the evolution of the CO~2~
plume after injection ceases, simulations using two smaller values of
S~grmax~ have also been run: a case with literature S~grmax~ values
halved, and a case with S~grmax~ = 0. The latter case is not expected to
be realistic, but provides useful information on limiting behavior.

**Table 3**. Scoping calculations comparing different amounts of
injected CO~2~ and different assumptions for S~grmax~.

  ------------ --------------------------- --------------------------------
  Literature                               
  values for                               
  maximum                                  
  residual gas                             
  saturation                               

  G05C         160 T: 80 T/day for 2 days  No CO~2~ arrival within 20 days
                                           -- plume immobilized before
                                           reaching observation well

  G05D         240 T: 80 T/day for 3 days  CO~2~ arrival at 9.1 days

  G05E         400 T: 80 T/day, for 5 days CO~2~ arrival at 4.6 days --
                                           arrival during injection
                                           (insensitive to S~grmax~)

  Half maximum                             
  residual gas                             
  saturation                               

  K05C         160 T: 80 T/day for 2 days  No CO~2~ arrival within 20 days
                                           -- plume immobilized before
                                           reaching observation well

  K05D         240 T: 80 T/day for 3 days  CO~2~ arrival at 7.0 days

  K05E         400 T: 80 T/day, for 5 days CO~2~ arrival at 4.5 days --
                                           arrival during injection
                                           (insensitive to S~grmax~)

  Zero maximum                             
  residual gas                             
  saturation                               

  J05C         160 T: 80 T/day for 2 days  CO~2~ arrival at 12.3 days

  J05D         240 T: 80 T/day for 3 days  CO~2~ arrival at 6.5 days

  J05E         400 T: 80 T/day, for 5 days CO~2~ arrival at 4.5 days --
                                           arrival during injection
                                           (insensitive to S~grmax~)
  ------------ --------------------------- --------------------------------

The Table 3 results for CO~2~ arrival time suggest that injecting for
three to four days at 80 T/day, might be a good starting point for
further scoping studies. The smaller plume produced by injecting only
two days becomes immobilized too easily under realistic conditions of a
non-zero value of S~grmax~, and the larger plume produced by injecting
for five days reaches the observation well under forced convection
conditions. Figures 14-17 show CO~2~ distributions at a series of times
for some of the cases. The color shading shows free-phase CO~2~ as gas
saturation S~g~ in the plane between the injection and observation
wells. The thin low-permeability marker bed is shown as a red line and
the single contour line shows the extent of the two-phase region. For
each case, the final frame shows the distribution of S~gr~ at one
selected time. By comparing the S~gr~ and S~g~ distributions for that
time, one can identify how mobile the CO~2~ plume is. Figure 14 shows a
complete time series including Frio I and Frio II for case G05C, while
Figures 15, 16, and 17 show just the Frio II part of the series for
cases G05D, G05E, and K05D, respectively.

Further studies will focus on attempting to constrain values of
S~grmax~, by further analysis of Frio I data and review of the
literature.

![](media/image29.png){width="5.997222222222222in"
height="4.0055555555555555in"}

**Figure 14**. Free-phase CO­~2~ distributions for a series of times for
Case G05C (typical values of S~grmax~) for Frio I and Frio II (time is
re-zeroed at the start of the Frio II injection).

![](media/image30.png){width="4.045833333333333in"
height="5.4118055555555555in"}

**Figure 15**. Free-phase CO­~2~ distributions for a series of times for
Case G05D (typical values of S~grmax~) for Frio II (time is re-zeroed at
the start of the Frio II injection).

![](media/image31.png){width="4.045833333333333in"
height="5.4118055555555555in"}

**Figure 16**. Free-phase CO­~2~ distributions for a series of times for
Case G05E (typical values of S~grmax~) for Frio II (time is re-zeroed at
the start of the Frio II injection).

![](media/image32.png){width="4.045833333333333in"
height="5.4006944444444445in"}

**Figure 17**. Free-phase CO­~2~ distributions for a series of times for
Case K05D (half typical values of S~grmax~) for Frio II (time is
re-zeroed at the start of the Frio II injection).

**[Pressure transient analysis]{.underline}**

As part of the Frio Brine Pilot, downhole pressure measurements were
obtained from both the injection well and observation well throughout
the carbon dioxide injection and recovery phases of the test. In
addition, a pre-injection interference test was used to obtain accurate
information about the permeability and compressibility of the formation.
By comparing the two data sets it is possible to obtain information on
field-scale relative permeability during carbon dioxide injection.
Analytical techniques have been used to interpret the pressure transient
data. In addition, a new inverse approach for deriving field-scale
relative permeabilities from pressure transient data has been developed.
This is the first time a data set such as this has been collected during
carbon dioxide injection into a saline formation. The results provide
important insights into the multi-phase flow behavior of carbon dioxide.
They also provide important information for predicting the injectivity
of carbon dioxide in saline formations.

As a first step in the analysis, the permeability of the formation was
measured from single phase pumping and drawdown tests. An example is
provided in Figure 18. A number for such tests were made and the
interpretation is summarized in Table 4.

During injection of CO~2~, the continuous formation pressure
measurements shown in Figure 19 were obtained. History matches of these
data using an analytical solution are shown in Figures 20 and 21. From
this, the relative permeability curves shown in Figure 22 were
determined. This new approach for measuring field-scale relative
permeability provides a method for quickly assessing a key parameter
needed to predict the transport of CO~2~ in saline formations.

![](media/image33.pct){width="4.0in" height="1.9861111111111112in"}

**Figure 18**. History match between measured and calculated drawdown,
resulting in estimates of the formation properties (see Table 4 below).

**Table 4**. Summary of formation parameters determined from the
pre-injection well tests.

+----------+-----------+-----------+----------+-----------+-----------+
| Active   | M         | Test Type | k (m^2^) | φch(m/Pa) | Comments  |
| Well     | onitoring |           |          |           |           |
|          | Well      |           |          |           |           |
+----------+-----------+-----------+----------+-----------+-----------+
| Pumping  | Injection | Drawdown  | 2        | 1.1x10-8  | M         |
|          |           |           | .2x10-12 |           | ulti-rate |
|          |           |           |          |           | analysis  |
+----------+-----------+-----------+----------+-----------+-----------+
| I        | Injection | Buildup   | 2        | 1.1x10-8  | s = 9     |
| njection |           |           | .1x10-12 |           |           |
|          |           |           |          |           | Mu        |
|          |           |           |          |           | lti-rate, |
|          |           |           |          |           | m         |
|          |           |           |          |           | ulti-well |
|          |           |           |          |           | analysis  |
+----------+-----------+-----------+----------+-----------+-----------+
| I        | Pumping   | Buildup   | 2        | 1.1x10-8  | Mu        |
| njection |           |           | .1x10-12 |           | lti-rate, |
|          |           |           |          |           | m         |
|          |           |           |          |           | ulti-well |
|          |           |           |          |           | analysis  |
+----------+-----------+-----------+----------+-----------+-----------+
| I        | Injection | Falloff   | 2        | 1.1x10-8  | s=12      |
| njection |           |           | .1x10-12 |           |           |
|          |           |           |          |           | Mu        |
|          |           |           |          |           | lti-rate, |
|          |           |           |          |           | m         |
|          |           |           |          |           | ulti-well |
|          |           |           |          |           | analysis  |
+----------+-----------+-----------+----------+-----------+-----------+

![](media/image34.pct){width="5.99375in" height="2.172222222222222in"}

**Figure 19**. Pressure buildup data collected during the CO~2~
injection.

![](media/image35.wmf){width="5.500694444444444in"
height="2.623611111111111in"}

**Figure 20**. Match between the measured and calculated pressure
buildup data at the injection well.

![](media/image36.wmf){width="5.372222222222222in"
height="2.5722222222222224in"}

**Figure 21**. Match between the measured and calculated pressure
buildup data at the observation well.

![](media/image37.wmf){width="4.814583333333333in" height="3.64375in"}

**Figure 22**. Relative permeability curves determined from the history
match of the pressure transient data.

**Task 2. Deploy and evaluate MMV and simulation technologies at the
Otway Basin Demonstration Site in Australia.**

The GEO-SEQ team has been asked to participate in the upcoming
demonstration project of geologic storage in the Otway Basin in
Australia. This provides a unique opportunity to gain new insights about
geologic storage of CO~2~ and improve MMV techniques. The demonstration
project will take place over a multi-year period and inject up to
100,000 tonnes of CO~2~ in gas and saline formations. The comparatively
large mass of CO~2~ that will be injected, combined with the opportunity
to leverage the large investment in this demonstration project by the
Australian government and industrial partners, provides a tremendous
opportunity for gaining experience with geologic storage of CO~2~ in
saline formations. The role of our team will be to:

-   Help identify the optimal suite of MMV technologies to deploy by
    using our forward and inverse geophysical simulator;

-   Deploy unique capabilities such as the U-tube sampler, multi-level
    sampler, noble gas tracers, and potentially, the P- and S- wave
    seismic source; and

-   Participate in the integrated interpretation and simulation of the
    fate and transport of the injected CO~2~.

    Not only does this test provide a unique opportunity for
    collaboration, but the injection formation is not unlike many
    potential storage formations present in the U.S.

***Task 2 Results and Discussion***

October 2005: LBNL group planning meeting to discuss deliverables. A
collaboration proposal was submitted to Australia:

  -----------------------------------------------------------------------
  ![](media/image38.wmf){width="4.995833333333334in"
  height="3.7368055555555557in"}

  -----------------------------------------------------------------------

November 2005: video conference held between LBNL and CO2CRC
collaborators to initiate workscopes. Teams from LBNL and CO2CRC were
designated to initiate workscopes in the following areas:

-   Flow Simulation

-   Geochemical Tracers

-   Experimentation /Design UTube

-   Seismic Design/Modeling

-   Coupled Reservoir Flow/Geomechanical Simulation

-   Pressure Transient Analysis

A draft of the collaborative workscope has been completed:

Otway Task 1. Modeling and Simulation

Task 1.1. Code Comparison (LBNL and CO2CRC)

Task 1.2. Code Enhancements (LBNL)

Task 1.3. Investigations of Non-isothermal Effects of CO~2~ Injection
(LBNL)

Task 1.4. Modeling Analyses for Site Characterization (LBNL and CO2CRC)

Task 1.5. Modeling Analyses of Pilot Test (LBNL and CO2CRC)

Otway Task 2. Geochemical Tracers and Fluid/Gas Sampling

> Task 2.1. Enhancement and deployment of the U-tube sampler for
> application to the Otway Pilot (LBNL and CO2CRC)
>
> Task 2.2. Install and deploy an on-site mass spectrometer for chemical
> analysis (LBNL and CO2CRC)
>
> Task 2.3. Collect baseline geochemical, isotopic and noble gas
> information on brine and gas samples (LBNL and CO2CRC)
>
> Task 2.4. Monitor and interpret carbon isotopes in the observation
> well (LBNL and CO2CRC)
>
> Task 2.5. Monitor and interpret SF6 and noble gas tracers in the
> observation well (LBNL and CO2CRC)
>
> Task 2.6. Use oxygen isotopes to monitor long term exchange of oxygen
> between CO~2~ and H~2~O (LBNL and CO2CRC)
>
> Task 2.7. Analyze and interpret major cation chemistry to evaluate
> H~2~O-CO~2~-rock interactions (LBNL and CO2CRC)

Otway Task 3. Active Source Seismic Monitoring

> Task 3.1. Drill a shallow well to deploy a permanent string of seismic
> sensors (LBNL and CO2CRC)
>
> Task 3.2. Use a surface seismic source to generate baseline
> reflections from the reservoir depth at a single location (LBNL and
> CO2CRC)
>
> Task 3.3. Repeat the source activation at regular intervals, possibly
> as a continuous source (LBNL and CO2CRC)
>
> Task 3.4. Interpret changes in reflected energy as changes in CO~2~
> saturation (LBNL and CO2CRC)

Otway Task 4. Coupled Reservoir-Geomechanical Fault Stability Analysis

Task 4.1. Code verification for fault stability analysis (LBNL and
CO2CRC)

> Task 4.2. Code enhancement for mechanically induced changes in fault
> hydrological properties (LBNL and CO2CRC)
>
> Task 4.3. Pre-injection fault stability assessment of the Pilot Test
> (LBNL and CO2CRC)

Task 4.4. Post-test fault stability analysis of the Pilot Test (LBNL and
CO2CRC)

Otway Task 5. Pressure Transient Data Collection and Analysis

Task 5.1. Assemble a hydrologic model and conducting pre-injection pump
test predictive calculations (LBNL and CO2CRC)

> Task 5.2. Install downhole and wellhead pressure and temperature
> gauges in the injection and observation wells (LBNL and CO2CRC)
>
> Task 5. 3. Pre-injection pump test data collection and interpretation
> (LBNL and CO2CRC)

Task 5.4. CO~2~ injection and observation well data collection and
analysis (LBNL and CO2CRC)

Curt Oldenburg traveled to Barossa, Australia to meet with collaborators
of the project. He attended the CO2CRC Annual Technical Meeting,
presented a talk on uses of CO~2~ injection in depleted gas reservoirs,
and discussed impacts of CO~2~ injection. A one on one meeting was held
to prioritize collaborative modeling tasks and to define a test problem
for code inter-comparison studies.

**Task 3. Use MMV techniques to evaluate the injectivity and
geomechanical response at the In Salah Gas Project in Algeria.**

### This test provides a unique opportunity to assess the effectiveness of industrial-scale CO~2~ storage in a low permeability formation that is representative of many sites in the U.S. The activity will be carried out in cooperation with the In Salah Joint Industry Project (JIP). Since June 2004, the In Salah Gas Project has been injecting nearly one million tonnes per year into the water-filled strata below a depleting gas reservoir. Unlike most CO~2~ storage sites, the permeability of the storage formation is low (\~ 5 md, less than 1% of the permeability at the Utsira Formation used at the Sleipner Project). In addition, the storage formation, with a thickness of 20 m, is also comparably thin. The small thickness combined with the low permeability results in the need for much higher pressures to inject CO~2~. To mitigate high injection pressures, the In Salah Gas Project decided to use long-reach horizontal wells for injection. Participation in this project provides the opportunity to assess the effectiveness of this approach for CO~2~ storage in low permeability formations.

### The In Salah JIP will carry out detailed monitoring of injection pressures, injection rates, surface fluxes and track subsurface migration of CO~2~ using a permanently installed seismic array. The GEO-SEQ activity will complement these planned activities by focusing on the injectivity of this low permeability formation and geomechanical effects due to injection in the unusual long-reach (up to 1.5 km) horizontal wells. Planned activities included obtaining measurements of the distribution of flow along the length of one or more of the horizontal injectors, measuring microseismic activity near the injection wells, obtaining satellite-based interferometry measurements that can assess land surface deformation, and potentially, deployment of tilt meters. These data will be analyzed using coupled flow and geomechanical models (TOUGH2 coupled to a geomechanical simulator). Based on what is learned here, an assessment will be made regarding the feasibility of using long-reach horizontal wells for injection into low permeability formations in other settings, particularly in the U.S.

***Task 3 Results and Discussion***

Work on this task will begin during the next quarter when funds become
available.

**Milestones Met**

Five abstracts of papers describing the Frio Brine Pilot were presented
at the AGU Annual meeting in December 2005. This completes the FY06 QTR1
Milestone. Copies of the abstracts are attached.

**Summary of Noteworthy Accomplishments**.

-   Mapping migration of CO~2~ using X-well seismic and Vertical Seismic
    Profiling (VSP) in a saline formation has been demonstrated for the
    first time at the Frio Brine Pilot.

-   A new method for measuring field-scale relative permeability from
    pressure transient test data has been developed.

-   Five papers describing the Frio Brine Pilot were presented at the
    AGU Annual meeting in December 2005. This completes the FY06 QTR1
    Milestone.

**Actual or Anticipated Problems or Delays.**

FY2006 funds are needed as soon as possible to assure that the Frio II
Pilot test can get underway in the spring of 2006.

**Upcoming Events**

January 12, 2006. Video-conference regarding the Otway Collaboration

March 20-22, 2006. International Symposium on Site Characterization for
CO~2~ Storage, Berkeley, CA.

March 14-16, 2006. In Salah SAB Meeting and Workshop, BP Institute,
Cambridge, UK.

**Seminars and Presentations**

October 2005. Second video conference between LBNL and CO2CRC
collaborators.

November 2005. CO2CRC Annual Technical Meeting, Barossa, Australia.

December 5-9, 2005. AGU Annual Fall Meeting. San Francisco, CA.

**Publications and Abstracts**

Benson, S.M., K. Pruess and C.A. Doughty, 2005, Pressure Buildup Data
Collection and Analysis During Carbon Dioxide Injection at the Frio
Brine Pilot, EOS Trans. AGU, 86(52), Fall Meet. Suppl., December 2005.

Daley, T.M., L.R. Myer, E.L. Majer, J.E. Peterson, 2005, Acquisition of
time-lapse, 6-component, P- and S-wave, crosswell seismic survey with
orbital vibrator and of time-lapse VSP for CO~2~ injection monitoring,
75th annual international meeting of the Society of Exploration
Geophysicists, Nov. 2005, Houston Tx.

Daley, T.M., Myer, L., Hoversten, G.M., Peterson, J.E., 2005, Borehole
Seismic Monitoring of Injected CO~2~ at the Frio Site, EOS Trans. AGU,
86(52), Fall Meet. Suppl., December 2005.

Doughty, C., 2005, Site Characterization for CO~2~ Storage and Vice
Versa: the Frio Brine Pilot as a Case Study, International Symposium on
Site Characterization for CO~2~ Geologic Storage, abstract submitted.

Doughty, C., 2005, Glow Modeling for CO~2~ Sequestration: The Frio Brine
Pilot, EOS Trans. AGU, 86(52), Fall Meet. Suppl., December 2005.

Freifeld, B.M., R.C. Trautz, Y.K. Kharaka, T.J. Phelps, L.R. Myer, S.D.
Hovorka and D.J. Collins, 2005, The U-tube: A Novel System for Acquiring
Borehole Fluid Samples from a Deep Geologic CO~2~ Sequestration
Experiment, J. Geophys. Res., 110, B10203, doi: 10.1029/2005JB003735.

Hovorka, S.D., S.M. Benson, C. Doughty, B.M. Freifeld, S. Sakuri, T.M.
Daley, Y.K. Kharaka, M.H. Holtz, R.C. Trautz, H. Seay Nance, L.R. Myer
and K.K. Knauss, 2005, Measuring Permanence of CO~2~ Storage in Saline
Formations─the Frio Experiment, Environmental Geosciences Special Issue,
submitted.

McCallum, S.D., T.J. Phelps, D.E. Riestenberg, B.M. Freifeld and R.C.
Trautz, 2005, Interpretation of Perfluorocarbon Tracer Data Collected
During the Frio Carbon Dioxide Sequestration Test, EOS Trans. AGU,
86(52), Fall Meet. Suppl., December 2005.

Trautz, R.C., B.M. Freifeld, C. Doughty, S.M. Benson, T.J. Phelps and
S.D. McCallum, 2005, Field Characterization of Reservoir Flow Paths
Using Miscible and Immiscible Tracer Tests, EOS Trans. AGU, 86(52), Fall
Meet. Suppl., December 2005.