geomechanical analysis of the naylor field, otway basin, australia (1)
TRANSCRIPT
International Journal of Greenhouse Gas Control 4 (2010) 827–839
Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control
journa l homepage: www.e lsev ier .com/ locate / i jggc
Geomechanical analysis of the Naylor Field, Otway Basin, Australia:
Implications for CO2 injection and storage
Sandrine VidalGilbert a,b,∗, Eric Tenthorey a,c, Dave Dewhurst a,d, Jonathan EnnisKing a,e,Peter Van Ruthb,f, Richard Hillis a,b
a The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Canberra, Australiab Australian School of Petroleum, University of Adelaide, Australiac Geoscience Australia, Canberra, Australiad CSIRO Petroleum, Perth, Australiae CSIRO Petroleum, Melbourne, Australiaf Woodside, Perth, Australia
a r t i c l e i n f o
Article history:
Received 25 August 2009
Received in revised form 1 June 2010
Accepted 4 June 2010
Available online 6 July 2010
Keywords:
Otway Basin Australia
In situ stress
Reservoir stress path
Fault stability
a b s t r a c t
A geomechanical assessment of the Naylor Field, Otway Basin, Australia has been undertaken to inves
tigate the possible geomechanical effects of CO2 injection and storage. The study aims to evaluate the
geomechanical behaviour of the caprock/reservoir system and to estimate the risk of fault reactivation.
The stress regime in the onshore Victorian Otway Basin is inferred to be strike–slip if the maximum hori
zontal stress is calculated using frictional limits and DITF (drilling induced tensile fracture) occurrence, or
normal if maximum horizontal stress is based on analysis of dipole sonic log data. The NW–SE maximum
horizontal stress orientation (142◦N) determined from a resistivity image log is broadly consistent with
previous estimates and confirms a NW–SE maximum horizontal stress orientation for the Otway Basin.
An analytical geomechanical solution is used to describe stress changes in the subsurface of the Naylor
Field. The computed reservoir stress path for the Naylor Field is then incorporated into fault reactivation
analysis to estimate the minimum pore pressure increase required to cause fault reactivation (1Pp).
The highest reactivation propensity (for criticallyoriented faults) ranges from an estimated pore pres
sure increase (1Pp) of 1 MPa to 15.7 MPa (estimated pore pressure of 18.5–33.2 MPa) depending on
assumptions made about maximum horizontal stress magnitude, fault strength, reservoir stress path
and Biot’s coefficient. The critical pore pressure changes for known faults at Naylor Field range from an
estimated pore pressure increase (1Pp) of 2 MPa to 17 MPa (estimated pore pressure of 19.5–34.5 MPa).
© 2010 Elsevier Ltd. All rights reserved.
1. Introduction
The geological storage of carbon dioxide (CO2) has been pro
posed as a potential method of reducing greenhouse gas emissions.
The Naylor Field in the Otway Basin, Victoria, has been chosen as
a demonstration site (The Otway Project) for the geological stor
age of CO2 by the Cooperative Research Centre for Greenhouse Gas
Technologies (CO2CRC). The Naylor Field is a small depleted nat
ural gas field, with the original gas cap area estimated at 40 hA.
The composition of the original gas (in mole %) is 88% methane, 4%
ethane, 2% propane, 1% carbon dioxide, 2% nitrogen, and 3% other
components. Total production from the target reservoir from June
2002 to October 2003 was 9.5 × 107 m3 (at standard conditions of
∗ Corresponding author at: Total, Gas & Power, Research and Development,
CO2 Geological Storage, Paris La Defense, France. Tel.: +33 1 47 44 24 61.
Email address: sandrine.vidal[email protected] (S. VidalGilbert).
15 ◦C and 0.101325 MPa). This was about 60% of the estimated gas
in place. Using equivalent volumes at reservoir conditions would
indicate a CO2 storage capacity of about 210,000 tonnes, but hys
teretic effects in relative permeability and the influx of formation
water from the adjoining aquifer may reduce this amount.
CO2rich gas has been produced from the nearby Buttress Field
and injected into the CRC1 borehole within the Naylor Structure
to demonstrate the viability of geological sequestration of CO2 in
Australia (Fig. 1). The injected gas has an average composition of 77
mole% carbon dioxide, 20 mole% methane and 3 mole% other gas
components. Between March 18, 2008 and August 28, 2009, 65,445
tonnes of this gas were injected into the Naylor Field’s Waarre C For
mation, containing about 58,000 tonnes of CO2. The reservoir was
monitored before, during and after injection via downhole pres
sure and temperature gauges in the injection well, fluid sampling
from the reservoir at the Naylor1 observation well (via three level
Utube assembly), and various geophysical methods including 4D
seismic and microseismic.
17505836/$ – see front matter © 2010 Elsevier Ltd. All rights reserved.
doi:10.1016/j.ijggc.2010.06.001
828 S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839
Fig. 1. Study area location map: CO2CRC Otway Project.
Subsurface injection of CO2 induces pore pressure variations
that affect the in situ stress state within the reservoir and its
surroundings. Injection of CO2 has the potential to increase pore
pressure and reduce fault stability in zones within and surround
ing the CO2 plume. The likelihood of fault reactivation is increased
when the pore pressure becomes elevated beyond a critical pres
sure change, which is controlled by parameters such as fault
orientation, and friction and cohesion within the fault plane. It is
therefore desirable to avoid exceeding the calculated pressure limit,
as fault reactivation may result in cap rock failure or permeabil
ity increase of the fault zone, both of which may result in vertical
leakage of CO2.
This paper outlines some of the geomechanical implications of
injecting CO2, with an emphasis on understanding fault stability
issues. In doing so, we also present calculations designed to incor
porate the effects of pore pressure/stress coupling, also known as
the reservoir stress path. The reservoir stress path refers to changes
in the horizontal stress field that are driven by variations in the
fluid pressure, and is a product of complex poroelastic interac
tions. Rather, than using a simplified effective stress law, stress
path prediction allows the evaluation of the mechanical stabil
ity of both reservoir/caprock system and bounding faults under
the injection loading condition. This paper will present results of
fault stability modelling for the Naylor Field by incorporating stress
path modelling and considering various fault property scenarios
and considering several different possibilities for the contemporary
stress field at Naylor.
2. Study area
The Naylor Field is located in the Port Campbell region, within
the onshore Otway Basin, Victoria, Australia (Fig. 1). The Nay
lor Field is a faultbound trap formed during the development
of the passive margin of southeastern Australia. Previous stud
ies show that the in situ stress field in the Otway Basin has
evolved from the normal fault stress regime associated with pas
sive margin development during the Jurassic to Cretaceous eras
to a strike–slip or reverse regime (Jones et al., 2000; Lyon et al.,
2005; Nelson et al., 2006; Rogers et al., 2008) associated with the
MioceneRecent compression (Schneider et al., 2004; Hillis et al.,
2008).
The target horizon for CO2 injection is the Late Cretaceous
Waarre Formation (Figs. 1–3). The Waarre Formation (2002 mSS
at CRC1 and 1977 mSS at Naylor1) is overlain by the Flaxmans
Formation (1972 mSS at CRC1 and 1954 mSS at Naylor1) and
the Belfast mudstone. The Late Cretaceous Waarre Formation in
the Naylor Field originally held a methanerich gas accumulation,
which was produced from June 2002 to October 2003. There was a
residual gas cap and the pressure increased following production
due to aquifer recharge. The pressure response to both depletion
and injection is shown for the Naylor1 well location in Fig. 4. This
site was selected as the location for a CO2 injection pilot project due
to the good porosity and permeability of its reservoir rock (the aver
age permeability was more than 1D). Furthermore, the reservoir
is overlain by the laterally extensive and thick Belfast mudstone,
which based on laboratory analyses should be able to support a
CO2 column height in the range of 607–851 m (contact angle: 0◦)
with an average of 754 m (Daniel, 2007). The Naylor site is also close
to the Buttress Field, a source of CO2rich gas (Watson and Gibson
Poole, 2005). The occurrence of natural high CO2 accumulations in
the Port Campbell Embayment demonstrates that traps in the area
are capable of containing CO2 over geological timescales (5 × 103
to 2 × 106 years: Watson et al., 2004).
There are three wells in the Naylor Field (Fig. 1). Naylor1 was
drilled in May 2001 and discovered a natural gas accumulation in
the Waarre C Formation. Naylor South1 was drilled in December
2001 and CRC1 was drilled by the CO2CRC in March 2007. For
the Otway Project, CRC1 was used as the CO2 injection well, with
Naylor1 being the updip monitoring well.
The Naylor Field is bound to the west by a north–south trend
ing normal fault (Naylor Fault). The Naylor Fault has an effective
juxtaposition seal because fault throw is insufficient to completely
offset the seal (Belfast mudstone). The Naylor Fault forms part of
the structural closure which contains the injected CO2 plume, and
is required to act as a longterm seal. The Naylor structure is also
cut to the east by a normal fault (Naylor East Fault) and it is bound
to the South by the Naylor South Fault (Fig. 3). Neither the Naylor
East Fault nor the Naylor South Fault is in the expected migration
S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839 829
Fig. 2. CRC1 and Naylor1 well section with formation tops (depths are in mSSTVD).
pathway of the injected CO2 plume. The faults bounding the Nay
lor field supported the initial natural gas column (initial Gas Water
Contact was ∼2015 mSS; Spencer et al., 2006), and the injected vol
ume of CO2 at subsurface conditions was smaller than the volume
of produced methane at the same conditions. Therefore, the faults
bounding the Naylor Field should have sufficient sealing capacity
to hold the CO2 volume injected. However, more research has to
be conducted regarding the sealing capacity of faults and how they
will respond to the different wettability and density of CO2 and
CH4. In this paper, the analysis will be focussed on potential fault
Fig. 3. Composite from the 3D seismic reflection survey going through the key wells with interpretated seismic horizons and main faults (Courtesy of T. Dance, CO2CRC).
830 S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839
reactivation, which may lead to increased fault zone permeability,
as a potential containment risk for CO2 storage projects within the
Waarre Formation in the Naylor Field.
3. Geomechanical model
The strength of a rock, and how much stress the rock supports
must be well constrained when trying to determine the reser
voir/cap rock integrity and fault stability. The geomechanical model
consists of in situ stress and rock strength data and provides the
basis for all geomechanical studies. The geomechanical model of the
onshore Victorian Otway Basin is outlined in the following section.
3.1. Neotectonic records and stress indicators from earthquakes
Estimation of the in situ stress state from petroleum data
combined with earthquake focal mechanism solutions and the neo
tectonic record provide important insights into the structural and
tectonic history of the region. Nelson et al. (2006) have discussed
the in situ stress state of southeast Australia and compared this with
earthquake focal mechanism solutions and the neotectonic record.
Their overview provides valuable baseline data for this geomechan
ical study.
Focal mechanism solutions reveal stresses in the deeper seismo
genic zone, which in SE Australia are typically between 5 and 20 km
(Allen et al., 2005). Comparing the in situ stresses from well data and
stress indicators from earthquakes allows investigation into stress
differences betweens basins and underlying basement. The Otway
Basin is relatively aseismic but dominantly strike–slip focal mech
anisms have been recorded to the north at Nhill in Victoria (east
of Victorian border, Fig. 1). The lateNeogene to recent geological
records of SE Australia indicate significant periods of faulting and
deformation (Dickinson et al., 2002; Sandiford et al., 2004), with
evidence for reverse faulting in the neotectonic record close to the
Victorian Otway Basin (Otway Ranges, Minerva anticline, Fig. 1).
3.2. In situ stress assessment
The geomechanical integrity of the reservoir is controlled by the
stress regime at the site and by the injection pressure. Stresses are
tensorial in nature and are characterized by magnitudes and orien
tations of the three principal components magnitudes, �1, �2 and
�3 which are orthogonal. A basic assumption is that the principal
stress directions are approximately vertical and horizontal. In this
case, the principal stresses are denoted �V for the vertical stress,
and �Hmax and �hmin for the maximum and minimum horizontal
stresses, respectively.
3.2.1. Orientation of maximum horizontal stress
The most commonly used information for inferring stress ori
entations is given by borehole breakouts. These symmetric spalled
regions are formed at various depths on the wellbore wall where
the compressive stress concentration exceeds the shear strength
of the rock. In vertical wells through transversely isotropic rocks,
breakout elongates the wellbore parallel to �hmin (Zoback, 2008).
The orientation of maximum horizontal stress was determined to
be N142 ± 5◦E from breakouts in the CRC1 borehole interpreted
on a resistivity image log (FMI) (Van Ruth, 2007). This maximum
horizontal stress orientation is broadly consistent with the regional
orientation and confirms a NW–SE maximum horizontal stress ori
entation in the onshore Victorian Otway Basin (Hillis et al., 1998;
www.asp.adelaide.edu.au/asm).
3.2.2. Magnitude of vertical stress
Vertical stress (�V) is the stress applied at any given point due
to the weight of the overlying rock mass and fluids. Vertical stress
Fig. 4. Measured pore pressure at CRC1 and Naylor1 wells.
magnitude can be estimated by integrating the bulk density log of
the overlying fluidsaturated rock with depth:
�V =
∫ D
0
�bgdz (1)
where g is the gravitational acceleration (9.81 m/s2), D is depth and
�b is the bulk density of the fluidsaturated rock.
Density logs used for estimating �V should be as complete as
possible. For the upper unlogged interval, bulk density was esti
mated using checkshot log velocities with empirical relationships
linking velocities and densities. The density predictions are made
using the lithologyspecific polynomial forms of the Gardner et al.
(1974) velocity–density relationships improved by Castagna et al.
(1993). Vertical stress values obtained for the onshore Victorian
Otway Basin indicate an average vertical stress gradient of about
21.45 MPa/km.
3.2.3. Magnitude of minimum horizontal stress
The minimum horizontal stress can be estimated by various
means. One way is using micro and minifracture tests, extended
leakoff tests and massive hydraulic fracture records to interpret
the fracture closure pressure, which corresponds to the minimum
horizontal stress magnitude. Conventional leakoff tests are com
pleted once leakoff occurs and as such, it is not possible to record
fracture propagation, shutin response and fracture closure. Con
sequently, if several leakoff pressure data are available, a “lower
bound” to these data should provide a reasonable estimate of the
minimum horizontal stress magnitude (Hawkes et al., 2005).
Nelson et al. (2006) have gathered a series of leakoff pres
sures, recorded in well completion reports and a series of
leakoff tests, performed in wells across the Victorian Otway Basin
(Fig. 5a). The average of these measurements indicates a gradi
ent of 18.5 MPa/km. The lower bound to these data is around
15.5 MPa/km. In addition, an extended leakoff test was undertaken
within the 512–519 mKB depth interval during the drilling of CRC1
(Van Ruth, 2007). The gradient determined from the extended leak
off test of CRC1 well is 14.5 MPa/km. This test has been performed
at relatively shallow depth compared to the target reservoir depth
(∼2000 mSS).
Berard et al. (2008) used extended leakoff test data, a bore
hole wall electrical image and dipole sonic log data from the well
CRC1 to constrain the principal horizontal stress orientations and
magnitudes. They conclude that the minimum and maximum hor
izontal stress gradients are on average, equal to 16 MPa/km and
18 MPa/km, respectively.
As no tests were undertaken at reservoir depth, the minimum
horizontal stress is poorly constrained. To consider all potential
assumptions, minimum horizontal stress gradients of 14.5 MPa/km
and of 18.5 MPa/km are used here.
S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839 831
Fig. 5. (a) Minimum horizontal stress estimates in the onshore Victorian Otway Basin and (b) Polygons which define possible stress magnitudes for Naylor field. Red line
shows the possible range for �Hmax assuming �hmin = 14.5 MPa/km (from CRC1 ELOT). (For interpretation of the references to colour in this figure legend, the reader is referred
to the web version of the article.)
3.2.4. Magnitude of maximum horizontal stress
The Frictional Limit method and the occurrence of DITF (Drilling
Induced Tensile Fractures) observed in two of the four image logs
in the Victorian Otway Basin (Nelson et al., 2006) have been used
to estimate the maximum horizontal stress. Frictional limits theory
states that the ratio of the maximum to minimum effective stress
cannot exceed the magnitude required to cause faulting on a criti
cally oriented, preexisting, cohesionless fault plane (Sibson, 1974).
Thus the magnitude of the maximum horizontal stress can be con
strained when the magnitude of the minimum horizontal stress is
known (Moos and Zoback, 1990). The frictional limit to stress is
given by:
�1 − ˛Pp
�3 − ˛Pp≤
{
√
(�2 + 1) + �
}2
(2)
where � is the coefficient of friction, Pp is the pore pressure, ˛ is
the Biot’s coefficient, �1 is the maximum principal stress and �3 is
the minimum principal stress.
Pore pressure was measured using Schlumberger’s Modular
Dynamics Tester (MDT) tool in the CRC1 borehole before and dur
ing CO2 injection (Fig. 4). Fig. 4 gives also pressure variations at
Naylor1 well during methane production and before CO2 injec
tion. The maximum principal stress is assumed to be the maximum
horizontal stress. Using Eq. (2), the maximum value for the max
imum horizontal stress gradient in the onshore Victorian Otway
Basin was constrained to ∼27 MPa/km at reservoir level using the
in situ stress gradient determined herein (�hmin ∼ 14.5 MPa/km,
�V ∼ 21.45 MPa/km, Pp ∼ 8.64 MPa/km just before CO2 injection,
February 2008) and assuming a coefficient of friction � = 0.6.
Nelson et al. (2006) used the occurrence of DITFs, knowl
edge of the �hmin and �V gradient (�hmin ∼ 18.5 MPa/km,
�V ∼ 21.45 MPa/km) and the assumption that the tensile strength of
the reservoir rocks are negligible to constrain the �Hmax gradient to
about 37 MPa/km in the Victorian Otway Basin. Taking the extended
leakoff test measurement from CRC1 (�hmin ∼ 14.5 MPa/km), the
occurrence of DITFs allow us to constrain the �Hmax gradient to
about 26 MPa/km in the Onshore Victorian Otway Basin.
Fig. 5b illustrates the allowable stress states at a depth of
2025 mGL (1977 mSS, the Waarre C top formation at Naylor1),
assuming that stress accumulation is limited by frictional limit
theory. The red line shows the range of possible values for the
maximum horizontal stress gradient, using a value of 14.5 MPa/km
for the minimum horizontal stress gradient. Depending on the
value used for the maximum horizontal stress, the faulting regime
may be either normal or strike–slip. DITF data and Frictional Limit
theory presented below suggest a strike–slip faulting regime and
the inversion of sonic scanner data from CRC1 well results in a
normal fault regime. In this study, three scenarios with different
assumptions for the stress regime (strike–slip fault regime: SSFR
and normal fault regime: NFR) given in Table 1, have been used in
a later section for assessing the risk of fault/fracture reactivation.
This described stress state is considered for the further modelling
as the “initial” stress state after depletion and just before CO2 injec
tion, in February 2008. In addition to the previously described in situ
stress regime, the stress alteration induced by CO2 injection has to
be determined for a better estimate of the fault reactivation risk.
This stress alteration is often identified as the reservoir stress path.
4. Reservoir stress path
The stresses acting within a reservoir are characterized by three
orthogonal stresses which are approximately vertical and horizon
tal. The two horizontal stresses are a combination of the lateral
effect of the overburden, the Poisson effect, plus any tectonic stress
change, or geometric constraint which results in different hori
zontal stress magnitudes (Addis, 1997). The pore pressure within
the formation also affects the horizontal stress magnitudes, both
in the initial state and during production. Exploitation of under
ground resources causes perturbation to the pore pressure profile.
If pore pressure changes during production/injection, the evolution
of the stresses with production/injection should also be considered,
as stress and pore pressure magnitudes are intrinsically linked. In
recent years there has been increasing evidence from oil field reser
voirs that changes to pore pressure may also impact directly on
the regional stress magnitudes due to complex poroelastic effects
832 S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839
Table 1
In situ stress tensor for a strike–slip fault and normal fault regime assumptions.
Scenario �V gradient
(MPa/km)
�hmin gradient
(MPa/km)
�Hmax gradient
(MPa/km)
Pp gradient
(MPa/km)
�Hmax orient.
(N)
Scenario 1: SSFR 21.45 14.5 26 8.64 142
Scenario 2: NFR 21.45 14.5 18 8.64 142
Scenario 3: SSFR 21.45 18.5 37 8.64 142
Fig. 6. Mohr circles, failure envelope and variation of Poisson’s ratio with effective confining pressure from laboratory tests on sandstones from the Waarre C Formation at
2056.4 mKB.
(Segall, 1989; Grasso, 1992; Addis, 1997; Hillis, 2001). This effect
is known as the reservoir stress path or stressdepletion response
(Addis, 1997) or pore pressurestress coupling (Hillis, 2001) and
is referred to as a decrease/increase in the minimum horizontal
stress accompanying depletion/injection. The reservoir stress path
is defined as the ratio of the change in minimum horizontal stress
(�hmin) to the change in pore pressure (Pp), and usually has a value
of 0.5–0.8 (Addis, 1997). Unfortunately, despite numerous obser
vations, this phenomenon remains rather poorly understood. The
reservoir stress path is not known before exploitation (produc
tion and/or injection) and analytical or numerical models for stress
development in reservoirs are very sensitive to the input param
eters. Furthermore, in some cases in the North Sea, some sort of
irreversibility has been observed in terms of reservoir path upon
repressurisation. The reservoir did not follow the same stress path
during depletion and during pressure rebound (Santarelli et al.,
1998).
Understanding the reservoir stress path during both depletion
and repressurisation is important for estimating the reservoir
compaction/expansion, surface movement, failure of intact rock
and near wellbore deformation, and it is required for identifying
minimum pore pressure required to cause fault reactivation. The
ideal procedure is to measure �Hmax and �hmin with in situ stress
measurements at initial reservoir conditions and at one or more
stages of pore pressure changes (Rhett and Risnes, 2002). Lacking
repeated in situ stress measurements, some analytical models, e.g.
uniaxial strain conditions and Eshelby’s solution (Rudnicki, 1999),
are used in this paper to estimate reservoir stress path.
4.1. The approach to uniaxial strain
It follows from linear poroelasticity that a reservoir will behave
under uniaxial strain conditions such that the reservoir stress path
equals:
ˇ =1�h
1Pp= ˛
(
1 − 2�
1 − �
)
(3)
where ˛ is the Biot’s coefficient (or effective stress parameter) is
usually assumed to be 1, but for sandstone this is not always the
case (Bouteca, 1994; Hettema et al., 1998; Addis, 1997). As Biot’s
coefficient is not always 1 for sandstones, a sensitivity analysis with
˛ = 0.7 and ˛ = 1 is performed here. Triaxial testing was undertaken
on core samples from Waarre Formation Unit C in the CRC1 bore
hole. The failure envelope shows a cohesive strength of just above
5 MPa and a friction coefficient of 0.76 (Fig. 6). The Poisson’s ratios
at different effective confining pressures for the sandstone reser
voir rock are given in Fig. 6. The Poisson’s ratio ranges from 0.22
to 0.32 so the resulting pore pressurestress coupling ratio ranges
from ˇ = 0.37 to ˇ = 0.71, assuming ˛ = 0.7 and ˛ = 1.
4.2. The solution of Eshelby
Rudnicki (1999) extended the solution of Eshelby (1957) to cal
culate the effects of geometry and elastic properties on altering the
local stress state. In this model, the theory of inhomogeneities is
used to solve induced stress changes within an ellipsoidal reservoir
(inhomogeneity) embedded in a surrounding material (host rock)
with different elastic properties. The formulations for injection or
withdrawal of fluid from a reservoir given in Rudnicki (1999) are
used in this paper. In the following equations, the subscripts I and
∞ stand for inhomogeneity (reservoir) and surrounding material,
respectively. The principal semiaxes of the ellipsoid are a and c
(with a = b in the horizontal plane) and the aspect ratio of the inho
mogeneity is e = c/a. Rudnicki demonstrated that the lateral stress
increment is:
1�h = ˛I�PIp
[
1 − E3 (1 + 2R) + E3 (1 − R)(1 − 2�I)
(1 + �I)
]
(4)
where ˛I is the Biot’s coefficient of the inhomogeneity and the other
terms are defined below.
For an axisymmetric reservoir, the ratio of lateral to axial strain
increments is given by the following expression:
R =3a − S33kk + g
{
3aS3333 − S33kkSpp33
}
2S33kk + g{
3aS3333 − S33kkSpp33
} (5)
With:
S33 = 1 −(1 − 2�∞)
2(1 − �∞)I(e) −
e2(2 − 3I(e))
2(1 − �∞)(1 − e2), Skk33 = 1 −
(1 − 2�∞)
(1 − �∞)I(e)
S33kk =(1 + �∞)
(1 − �∞)(1 − I(e)), I(e) =
e2
(1 − e2)3/2
{
ar cos(e) − e(1 − e2)1/2
}
a=1
3
(1 + �∞)
(1 − �∞), g =
GI
G∞
− 1, E3 =a(1 − k)
(1 + 2R)(1 + ak) + g(1 − R)(Skk33 − a)
and k =KI
K∞
− 1
(6)
S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839 833
Fig. 7. Reservoir stress path against inhomogeneity Poisson’s ratio (a) for different ratios of bulk moduli and Biot’s coefficient of 1, (b) for different ratios of shear moduli and
Biot’s coefficient of 1, (c) for different ratios of bulk moduli and Biot’s coefficient of 0.7 and (d) for different ratios of shear moduli and Biot’s coefficient of 0.7.
Based on the laboratory data from Fig. 5, the Poisson’s ratio of
the inhomogenity (�I) ranges from 0.22 to 0.32; Rudnicki (1999)
assumed that the dependence on Poisson’s ratio of the surround
ing material (�∞) is weak. GI/G∞ and KI/K∞ are inferred from sonic
log data. Pwave and Swave velocities and density logs are used
to compute dynamic undrained moduli. Using BiotGassmann’s
equation, a saturation correction is applied to dynamic undrained
moduli to obtain dynamic drained moduli. Then, empirical rela
tionships between drained static and drained dynamic Young’s
moduli are applied (Wang, 2000; VidalGilbert et al., 2009). This
approach gives an approximate value for GI/G∞ = 2 and KI/K∞ = 2.
The aspect ratio of the inhomogeneity (e) used in this evaluation is
0.0187. As the actual reservoir geometry is not fully represented
by an axisymetric ellipsoid, a sensitivity analysis has been car
ried out with different values ranging from 0.018 to 0.03 for the
aspect ratio in order to evaluate the impact on the stress path
evaluation. The results show that this parameter does not have a
major influence on the stress path estimation for this particular
reservoir.
Fig. 7a and c presents the reservoir stress path (ratio of lateral
stress increment to pore pressure increment) against the Poisson’s
ratio of the inhomogeneity for different ratios of bulk moduli and for
a Biot’s coefficient of 0.7 and 1, respectively. Fig. 7b and d presents
the reservoir stress path (ratio of lateral stress increment to pore
pressure increment) against the Poisson’s ratio of the inhomogene
ity for different ratios of shear moduli and for a Biot’s coefficient
of 0.7 and 1, respectively. Assuming that the Poisson’s ratio of
the inhomogenity ranges from 0.22 to 0.32, Fig. 7a–d shows that
the reservoir stress path ranges from ˇ = 0.36 to ˇ = 0.75 assuming
GI/G∞ = 2, KI/K∞ = 2 and ˛ = 0.7 and 1. The results of this solution are
used for the reservoir stress path estimation (ˇ = 0.4 and ˇ = 0.8) to
study the likelihood of fault reactivation during CO2 injection.
5. Geomechanical risking
The injection of CO2 into the subsurface will result in an increase
in the reservoir pore pressure. Increasing pore pressure can cause
brittle failure of rocks, which will occur when the stress acting on
a rock exceeds rock strength. The maximum pore pressure which
can be sustained by faults and intact rock can be estimated from
geomechanical risking (Root et al., 2004; Streit and Hillis, 2004).
In this paper, the reservoir stress path and fault stability analysis
were not studied during the depletion phase. The presented “initial”
state is considered after depletion and before CO2 injection.
5.1. Pore pressure required for inducing faulting
Inducing slip on an inactive fault provides a possible path for
leakage. Slip will occur on a fault when the maximum shear stress
acting in the fault plane exceeds the shear strength of the fault. In
a 2D analysis, the magnitudes of the shear stress (�) and normal
stress (�n) acting on this plane are given by:
� =�1 − �3
2sin 2� and �n =
�1 + �3
2+
�1 − �3
2cos 2� (7)
834 S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839
where �1 is the maximum principal in situ stress, �3 is the minimum
principal in situ stress and � is the angle between the fault plane and
the �3 direction. A Mohr–Coulomb shear failure criterion is then
used to characterize the fault strength:
� = c +(
�n − ˛Pp
)
� (8)
where � is the critical shear stress for slip to occur, c is the fault
cohesion, � is the fault friction coefficient (� = tan ϕ where ϕ is the
fault friction angle), �n is the normal stress, ˛ is the Biot’s coefficient
and Pp is the pore pressure in the fault plane. The faults are often
assumed to be cohesionless and the friction coefficient is typically
in the range of � = 0.6 to 0.85 (Byerlee, 1978).
Substituting Eq. (7) into Eq. (8), the pore pressure required to
reactivate fault is expressed as followed:
Pp =1
˛
[
1
2(�1 + �3) +
1
2(�1 − �3) cos 2� −
1
2(�1 − �3)
sin 2�
�
]
(9)
5.1.1. Normal fault regime (NFR)
In normal fault stress regimes, the maximum principal stress �1
is vertical and is denoted �V and the minimum principal stress �3
is horizontal and is denoted �h. The faults which are most likely
to slip first in any setting are those that contain the intermediate
principal stress axis. In such a case, the intermediate principal stress
(�2 = �H) can be neglected (Hawkes et al., 2004).
The reservoir stress path ratio can be combined with the
Mohr–Coulomb criterion for failure in normal fault stress regimes
and a new equation is derived for the pore pressure injection levels
that can induce slip on faults. The total horizontal stress (�h) can
be written as function of the initial pressure (Ppi) and the change
in total horizontal stress (1�h) induced by injection:
�h = �h0 +1�h
1Pp(Pp − Ppi) or �h = �h0 + ˇ(Pp − Ppi) (10)
The failure criterion given in Eq. (9) can now be rewritten using
Eq. (10):
Pp =1
˛
(1/2)(�v + �h) + (1/2)(�v − �h) cos 2�−(1/2)(�v − �h)(sin 2�/�)
1 − (1/2)ˇ(1 − cos 2� + (sin 2�/�))
−(1/2)ˇPpi(1 − cos 2� + (sin 2�/�))
1 − (1/2)ˇ(1 − cos 2� + (sin 2�/�))
]
(11)
For a normal fault stress regime (scenario 2, Table 1), � is the fault
dip angle. Calculations of pore pressure levels required to cause
faulting are conducted for the Naylor field using the normal fault
in situ stress assumption given in Table 1. The total vertical stress
is approximately 43.4 MPa, while the minimum horizontal stress
is 29.4 MPa at a pore pressure (Ppi) of 17.5 MPa in the initial state
within the reservoir at a depth of 2025 mGL (1977 mSS, the Waarre
C reservoir top formation at Naylor1).
Fig. 8 shows pore pressure that is estimated to cause fault reacti
vation assuming that the total horizontal stress are constant (ˇ = 0),
and that Biot’s coefficient ˛ = 1. In this configuration, the increase
in pore pressure required to reactivate a fault with a dip angle of
60◦ is 1Pp = 5.3 MPa, with Ppi = 17.5 MPa. For the same pore pres
sure increase and considering a reservoir stress path of ˇ = 0.4 and
of ˇ = 0.8, the stress state is far from the failure line. Regarding
ˇ = 0.4 scenario, the pore pressure increase required to cause fault
reactivation is 1Pp = 12.9 MPa and regarding ˇ = 0.8 scenario, fault
stability is never jeopardized, even at large pore pressures. Table 2
summarizes pore pressure increase required to cause fault reacti
vation (1Pp) assuming a normal fault stress regime (scenario 2), a
Biot’s coefficient of ˛ = 0.7 or 1 and a reservoir stress path of ˇ = 0
or 0.4.
Fig. 8. Scenario 2: NFR – Mohr–Coulomb circle assuming a pore pressure varia
tion of 5.3 MPa without any pore pressure/stress coupling ratio (ˇ = 0), with a pore
pressure/stress coupling ratio ˇ = 0.4 and ˇ = 0.8, assuming ˛ = 1.
5.1.2. Strike–slip fault regime (SSFR)
The pore pressure/stress coupling ratio has not been clearly
established for maximum horizontal stress for strike–slip stress
regimes. Hawkes et al. (2004) recommend using sitespecific, cou
pled reservoirgeomechanical simulations for such conditions.
Nevertheless, the maximum horizontal stress path and the min
imum horizontal stress path have been assumed to be similar (Rhett
and Risnes, 2002) so Eq. (9) becomes:
Pp =1
˛
(1/2)(�H + �h) + (1/2)(�H − �h) cos 2�−(1/2)(�H − �h)(sin 2�/�)
1 − (1/2)ˇ−
ˇPpi
1 − ˇ
(12)
For a strike–slip fault regime, � is the angle between the strike
of a vertical fault and �h.
Calculations of pore pressure levels required to cause faulting
are conducted for the Naylor field using the strike–slip fault in situ
stress assumptions given in Table 1.
For scenario 1 given in Table 1, the maximum horizontal stress
is 52.6 MPa, while the minimum horizontal stress is 29.4 MPa at a
pore pressure of 17.5 MPa at the initial state within the reservoir at a
depth of 2025 mGL (1977 mSS, the Waarre C reservoir top formation
at Naylor1).
Fig. 9 shows pore pressure that is estimated to cause fault
reactivation assuming that the total horizontal stresses are con
stant (ˇ = 0) and that Biot’s coefficient ˛ is 1. When the total
horizontal stresses are assumed constant, the increase in pore
Fig. 9. Scenario 3: SSFR – Mohr–Coulomb circle assuming a pore pressure varia
tion of 2 MPa without any pore pressure/stress coupling ratio (ˇ = 0), with a pore
pressure/stress coupling ratio ˇ = 0.4 and ˇ = 0.8, assuming ˛ = 1.
S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839 835
Table 2
Pore pressure increase (1Pp) required to reactivate critically oriented faults depending on assumptions made about in situ stress regime, fault strength, reservoir stress path
and Biot’s coefficient.
Scenario Stress regime Fault strength Reservoir stress path Biot’s coefficient 1Pp (MPa) Pp (MPa)
Scenario 1 SSFR Cohesionless faults ˇ = 0 ˛ = 1 1 18.5
SSFR Cohesionless faults ˇ = 0.4 ˛ = 1 1.8 19.3
SSFR Cohesionless faults ˇ = 0 ˛ = 0.7 8.9 26.4
SSFR Cohesionless faults ˇ = 0.4 ˛ = 0.7 9.9 27.4
SSFR Healed faults ˇ = 0 ˛ = 1 10.8 28.3
SSFR Healed faults ˇ = 0.4 ˛ = 1 11.5 29
SSFR Healed faults ˇ = 0 ˛ = 0.7 22.9 40.4
SSFR Healed faults ˇ = 0.4 ˛ = 0.7 23.9 41.4
Scenario 2 NFR Cohesionless faults ˇ = 0 ˛ = 1 5.3 22.8
NFR Cohesionless faults ˇ = 0.4 ˛ = 1 12.9 30.4
NFR Cohesionless faults ˇ = 0 ˛ = 0.7 15.1 32.6
NFR Cohesionless faults ˇ = 0.4 ˛ = 0.7 25.9 43.4
NFR Healed faults ˇ = 0 ˛ = 1 13.9 31.4
NFR Healed faults ˇ = 0.4 ˛ = 1 20.7 38.2
NFR Healed faults ˇ = 0 ˛ = 0.7 27.3 44.8
NFR Healed faults ˇ = 0.4 ˛ = 0.7 37 54.5
Scenario 3 SSFR Cohesionless faults ˇ = 0 ˛ = 1 2.3 19.8
SSFR Cohesionless faults ˇ = 0.4 ˛ = 1 3.8 21.3
SSFR Cohesionless faults ˇ = 0 ˛ = 0.7 10.8 28.3
SSFR Cohesionless faults ˇ = 0.4 ˛ = 0.7 12.9 30.4
SSFR Healed faults ˇ = 0 ˛ = 1 14.3 31.8
SSFR Healed faults ˇ = 0.4 ˛ = 1 15.7 33.2
SSFR Healed faults ˇ = 0 ˛ = 0.7 27.9 45.4
SSFR Healed faults ˇ = 0.4 ˛ = 0.7 29.9 47.4
pressure required to reactivate a fault is 1Pp = 1 MPa, with
Ppi = 17.5 MPa. In contrast, the increase in pore pressure is approx
imately 1Pp = 1.8 MPa and 1Pp = 5 MPa when reservoir stress path
followed by the in situ stresses during CO2 injection is ˇ = 0.4 and
ˇ = 0.8, respectively. In this in situ stress regime, the size of the circle
is not changed because it has been assumed that the minimum hor
izontal stress path is the same as the maximum horizontal stress
path. Table 2 summarizes the pore pressure increase required to
cause fault reactivation (1Pp) assuming a strike–slip fault stress
regime (scenarios 1 and 3), a Biot’s coefficient of ˛ = 0.7 or 1 and a
reservoir stress path of ˇ = 0 or 0.4.
5.2. Fault stability analysis
The risk of fault reactivation is calculated using the 3D formu
lation in Eqs. (7)–(12) and the geomechanical model described
in Table 1. This technique determines fault reactivation risk by
estimating the increase in pore pressure required to cause fault
reactivation (Mildren et al., 2002; Streit and Hillis, 2004). The mag
nitude of the normal stress across the fault and the shear stress
are calculated through 3D relationships established by a change of
Cartesian reference system from the stress tensor across any fault.
The minimum pore pressure increase required to cause reac
tivation for cohesionless faults in the Otway Basin at 2025 m is
shown in Fig. 10. This figure presents plots of poles to planes,
assuming ˇ = 0 and ˛ = 1, for the three stress regime scenarios
described in Table 1. The orientation of faults with high and low
fault reactivation propensity differs for faults when the maximum
horizontal stress was predicted assuming a strike–slip fault regime
and when the maximum horizontal stress was predicted assuming
a normal fault regime. In the strike–slip fault regime assumption,
subvertical faults that strike roughly 60◦ from the minimum hor
izontal stress have the highest fault reactivation propensity (hot
colours in Fig. 10a and c). The highest reactivation risk for critically
oriented cohesionless faults is estimated to be 1 MPa for scenario 1
and 2.3 MPa for scenario 3. In the normal fault regime assumption,
faults that strike subparallel to the maximum horizontal in situ
stress and dip at roughly 60◦ have the highest fault reactivation
propensity (hot colours in Fig. 10b). The highest reactivation risk
for critically oriented cohesionless faults in scenario 2 is estimated
to be 5.3 MPa.
The same risk of fault reactivation is presented below incorpo
rating into equations of fault stability the estimated stress paths
followed by the in situ stresses during CO2 injection. The fault
stability analysis incorporating reservoir stress path (ˇ = 0.4) is
illustrated on Fig. 11. Incorporating the reservoir stress path (ˇ)
into the fault stability equations gives a higher value for the estima
tion of maximum sustainable pore pressure. This tendency is more
pronounced for normal fault stress regime assumption (scenario
2) where the minimum 1Pp is 12.8 MPa assuming ˇ = 0.4 whereas
1Pp is 5.3 MPa assuming ˇ = 0.
A sensitivity analysis has been performed to estimate the
fault reactivation propensity depending on assumptions made
about maximum horizontal stress magnitude (scenarios 1, 2 and 3
described in Table 1), fault strength (cohesionless faults with C = 0
and � = 0.6 and healed faults with C = 5 MPa and � = 0.76), reservoir
stress path (ˇ = 0, constant horizontal stress and ˇ = 0.4) and Biot’s
coefficient (˛ = 0.7 and ˛ = 1).
Table 2 summarizes the results of this analysis. The highest reac
tivation propensity (for critically oriented faults) ranges from an
estimated pore pressure increase (1Pp) of 1–37 MPa, with an initial
pore pressure at the top of the reservoir (Ppi) of 17.5 MPa.
Among the sensitivity analysis results, the most risky scenarios
are cohesionless faults when:
1. SSFR with ˛ = 1 and ˇ = 0 or 0.4, with low horizontal stress sce
nario: 1Pp = 1 MPa, Pp = 18.5 MPa
2. SSFR with ˛ = 1 and ˇ = 0 or 0.4, with high horizontal stress sce
nario: 1Pp = 2.3 MPa, Pp = 19.8 MPa
3. NFR with ˛ = 1 and ˇ = 0: 1Pp = 5.3 MPa, Pp = 22.8 MPa
In addition, it could be noted that nonzero values of reservoir
stress path (ˇ) and nonunity values of Biot’s coefficient (˛), both
of which are likely, decrease the risk of fault reactivation in all
scenarios.
836 S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839
Fig. 10. Stereonets showing the fault reactivation propensity (1Pp) at 2025 m depth in the Otway Basin. Faults are plotted as poles to planes. The results are presented for
cohesionless faults assuming a reservoir stress path of ˇ = 0 (constant horizontal stresses), a Biot’s coefficient of ˛ = 1 (a) for scenario 1, strike–slip fault stress regime (b) for
scenario 2, normal fault stress regime and (c) for scenario 3, strike–slip fault stress regime.
Fault reactivation propensity has also been evaluated for three
key faults within the Naylor structure with known orienta
tions using maximum horizontal stress calculations from Table 1
(Fig. 12). Fault reactivation propensity is calculated using the cohe
sionless fault strength scenario. Faults are coloured according to
reactivation propensity (1Pp). High values of 1Pp (cool colours)
indicate low reactivation propensity, whereas low values of 1Pp
(warm colours) indicate high reactivation propensity. Comparison
of the three model runs shows that the normal fault regime results
in a more stable fault condition, in which larger increases in pore
pressure can be supported. The fault segment with highest fault
reactivation propensity in the Naylor Field is at the base of the Nay
lor Fault near Naylor1 well, when fault reactivation propensity is
calculated with a SSFR regime assumption (scenarios 1 and 3).
6. Discussion
The minimum pore pressure increase required to cause fault
reactivation (1Pp) for critically oriented faults ranges from 1 MPa
to 37 MPa, with an initial pore pressure at the top of the reser
voir (Ppi) of 17.5 MPa, depending on assumptions made about
stress regime, fault strength, reservoir stress paths and Biot’s
coefficient. Two fault strength scenarios were used to evalu
ate the potential for fault reactivation; healed faults (C = 5 MPa
and � = 0.76) and cohesionless faults (C = 0 MPa and � = 0.6).
In addition, three stress regimes have been considered:
SSFR with �hmin = 14.5 MPa/km and �Hmax = 26 MPa/km; NFR
with �hmin = 14.5 MPa/km and �Hmax = 18 MPa/km; SSFR with
�hmin = 18.5 MPa/km and �Hmax = 37 MPa/km. The vertical stress
gradient is constant (�V = 21.45 MPa/km) for all cases. The resultant
maximum horizontal stress magnitudes suggested a strike–slip
fault regime where the occurrence of DITF was used and a normal
fault regime where the CRC1 sonic log inversion was used.
Therefore, fault reactivation analyses differ in terms of which
fault orientations have high or low fault reactivation propensity
depending on the method that was used to calculate maximum
horizontal stress.
Taking into account the model uncertainties, a sensitivity
analysis has been performed to estimate the fault reactiva
tion propensity for critically oriented faults. The most risky
scenarios are a cohesionless fault in a strike–slip regime
(1Pp = 1 MPa, Pp = 18.5 MPa, with low horizontal stress gradient
and 1Pp = 2.3 MPa, Pp = 19.8 MPa, with high horizontal stress gradi
ent). The normal fault regime is a less risky scenario (1Pp = 5.3 MPa,
Pp = 22.8 MPa).
The risk of the fault reactivation presented incorporates stress
paths followed by the in situ stress within the reservoir during CO2
injection with equations of fault stability. This model shows the
important role of stress path on fault stability. Nonzero values of
reservoir stress path (ˇ = 0.4) means that horizontal stress is not
constant, decreasing the risk of fault reactivation in all scenarios:
1Pp = 1.8 MPa, Pp = 19.5 MPa for scenario 1 (SSFR); 1Pp = 12.9 MPa,
S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839 837
Fig. 11. Stereonets showing the fault reactivation propensity (1Pp) at 2025 m depth in the Otway Basin. Faults are plotted as poles to planes. The results are presented for
cohesionless faults assuming a reservoir stress path of ˇ = 0.4, a Biot’s coefficient of ˛ = 1 (a) for scenario 1, strike–slip fault stress regime (b) for scenario 2, normal fault stress
regime and (c) for scenario 3, strike–slip fault stress regime.
Pp = 30.3 MPa for scenario2 (NFR); and 1Pp = 3.8 MPa, Pp = 21.3 MPa
for scenario 3 (SSFR), cohesionless fault with ˇ = 0.4, instead
of 1Pp = 1 MPa, Pp = 18.5 MPa, 1Pp = 5.3 MPa, Pp = 22.8 MPa and
1Pp = 2.3 MPa, Pp = 19.8 MPa for scenarios 1, 2 and 3 respectively,
cohesionless fault with ˇ = 0, at the top of the reservoir at Naylor1
well. However, this result depends on the assumption made about
the maximum horizontal stress path. Lacking repeated in situ stress
measurements, some analytical models were used and both min
imum and maximum horizontal stress paths were assumed to be
equal.
In addition, nonunity of the Biot’s coefficient (˛ = 0.7) decreases
further the risk of fault reactivation. The uncertainty linked to this
parameter could be minimized with appropriate laboratory mea
surements. This work is planned using cores from an adjacent field
to infer the Biot’s coefficient value.
Fault reactivation is one of the geomechanicsrelated risk fac
tors for loss of containment of injected CO2. Hydraulic fracturing
and especially the risks associated with outofreservoir fracture
growth are to be avoided. To avoid migration through new frac
tures, the pore pressure must remain below the fracture gradient
to ensure that fracturing is not induced. A conservative upper
bound on injection pressure is the magnitude of the minimum in
situ stress (�3) (Hawkes et al., 2005). In this study, the minimum
in situ stress is the minimum horizontal stress for all scenarios:
�hmin = 29.3 MPa for scenarios 1 and 2 and �hmin = 37.5 MPa for sce
nario 3. This threshold for injection pressure precludes some results
presented in light yellow in Table 2. As a result, the possible val
ues for minimum pore pressure increase required to cause fault
reactivation (1Pp) for critically oriented faults ranges from 1 MPa
to 15.7 MPa, with an initial pore pressure at the top of the reser
voir (Ppi) of 17.5 MPa (estimated pore pressure of 18.5–33.2 MPa),
considering the magnitude of the minimum in situ stress as the
threshold for injection pressure. This range for minimum pore
pressure increase required to cause fault reactivation is given for
critically oriented fault planes which are not observed at the Nay
lor Field. Nevertheless, the pore pressure increase required to cause
fault reactivation for known fault planes at the Naylor Field ranges
from 2 MPa to 17 MPa (estimated pore pressure of 19.5–34.5 MPa)
(Fig. 12).
The analytical model presented in this paper is useful to provide
an initial estimate of the stress changes with simplified reservoir
geometry and an assumed uniform pore pressure distribution. This
provides an easy way to perform sensitivity analysis. To better
infer the in situ stress changes with heterogeneous poromechan
ical properties (various geological facies) with accurate reservoir
geometry and with the modelled pore pressure change distribution
within the reservoir, it is essential to perform a 3D geomechanical
modelling.
In fact, if the pore pressure change within the reservoir is highly
localized, the induced stress changes may be significant in the
bounding seal. The analysis detailed in this paper is focused on the
reservoir itself but it is also relevant to seal integrity. If faults are
reactivated or shear fractures are induced in the reservoir, they
could potentially propagate through the seal, thereby compromis
838 S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839
Fig. 12. Fault reactivation propensity for all faults (a) using scenario 1: SSFR assump
tion, (b) using scenario 2: NFR assumption and (c) using scenario 3: SSFR assumption.
ing its hydraulic integrity. Due to the high permeability of Waarre C
Formation, and the relative modest injection rates (averaging about
124 tonnes per day), there are not large pressure gradients in the
near wellbore region, and so there is no risk of compromising seal
integrity near the injection well.
Fig. 13. Pore pressure profile simulated at Naylor fault.
There is also the concern that thermal stresses from injected
CO2 colder than the formation might affect seal integrity near the
injection well. Temperature measurements from downhole gauges
in CRC1 indicate that the injected gas at the reservoir level is about
20 ◦C cooler than the reservoir temperature. However the comple
tion interval in CRC1 is at some distance below the main top seal,
the Belfast mudstone, and nonisothermal simulations of injection
indicate that the temperature change is only significant very close
to the well. The possible effect of thermal stresses is still being
examined, but so far there is no evidence to suggest any significant
changes in permeability near the well.
Between March 2008 and August 2009, 65,445 tonnes of CO2
rich gas were injected at CRC1, with a pore pressure increase at the
CRC1 well location of approximately 1.5 MPa (Fig. 4). The reservoir
simulation updated with the latest acquired data (Fig. 13) esti
mates a pore pressure of 18.5 MPa at the Naylor Fault at the base of
the reservoir where the reactivation propensity is highest. In some
studied scenarios, the minimum pore pressure required to reac
tivate a fault is 18.5 MPa at the top of the reservoir and roughly
19 MPa at the bottom of the reservoir. The microseismic array
deployed in the Naylor1 well has recorded microseismic events
that may be attributable to fault movement, but the spatial uncer
tainty exceeds 200 m. Careful monitoring will help us to improve
our understanding of reservoir behaviour. In addition, more in situ
stress measurements will allow us to discriminate between the dif
ferent assumptions that are made about the stress field regime, the
fault strength and the reservoir stress path.
7. Conclusion
When assessing the suitability of possible CO2 storage sites,
it is important to evaluate whether injectionrelated fluid pres
sure increases could reactivate preexisting faults and generate
new fractures. Such brittle deformation could increase permeabil
ity and promote unwanted movement of CO2 out of the intended
storage area. Thus, in order to evaluate the fault reactivation
propensity during injection, a geomechanical analysis of the Nay
lor Field, Otway Basin, Victoria was undertaken. Appropriate stress
orientations and gradients were determined from field data, with
laboratory testing providing geomechanical properties of reservoir
rock samples. The stress regime in the onshore Victorian Otway
Basin was assumed to be strike–slip if maximum horizontal stress
is estimated using frictional limit and DITF occurrence but normal
if maximum horizontal stress is determined by sonic log inversion
from CRC1 well. As a result of the conflicting data and other geome
chanical uncertainties, we performed sensitivity analyses using
S. VidalGilbert et al. / International Journal of Greenhouse Gas Control 4 (2010) 827–839 839
both stress fields and a range of potential geomechanical property
inputs.
Injection of CO2 into the reservoir results in some perturba
tion to the pore pressure profile and thus to some alterations in
the in situ stress field acting on the reservoir and on its close
surroundings. Some analytical models were used to estimate the
stress paths followed by the in situ stresses. The geomechani
cal model and the reservoir stress paths were used to estimate
the maximum sustainable pressure to avoid fault slip at injec
tion site. The highest reactivation propensity (for critically oriented
faults) ranges from an estimated pore pressure increase (1Pp) of
1–15.7 MPa (estimated pore pressure of 18.5–33.2 MPa) depending
on assumptions made about maximum horizontal stress mag
nitude (SSFR with �hmin = 14.5 MPa/km and �Hmax = 26 MPa/km;
NFR with �hmin = 14.5 MPa/km and �Hmax = 18 MPa/km; SSFR with
�hmin = 18.5 MPa/km and �Hmax = 37 MPa/km), fault strength (C = 0
and � = 0.6; C = 5 MPa and � = 0.76), reservoir stress path (ˇ = 0, con
stant horizontal stress and ˇ = 0.4) and Biot’s coefficient (˛ = 0.7
and ˛ = 1) and considering the magnitude of the minimum in situ
stress at the threshold for the injection pressure. For the fault
known at Naylor Field, the critical pore pressure changes range
from an estimated pore pressure increase of 2–17 MPa (estimated
pore pressure of 19.5–34.5 MPa).
The geomechanical model illustrates the important role of Biot’s
coefficient and reservoir stress path in controlling the risk of fault
reactivation. Availability of field data and in situ stress measure
ments obtained during the CO2 injection within the reservoir will
improve and constrain the accuracy of the geomechanical model.
Acknowledgements
The authors acknowledge the funding provided to the Coopera
tive Research Centre for Greenhouse Gas Technologies (CO2CRC) by
the Commonwealth of Australia to enable this research to be under
taken. The authors also wish to acknowledge three other CO2CRC
contributors: Ric Daniel from the Australian School of Petroleum,
University of Adelaide, Australia for fruitful discussions on seal
capacity of caprocks, Tess Dance from CSIRO Petroleum Resources,
Perth, Australia for providing the geological model and Andy Nicol
from GNS Science, NewZealand for reviewing this paper. The sug
gestions for paper improvement from the journal reviewers are
greatly appreciated.
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