geomechanical analysis of the naylor field, otway basin, australia (1)

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).


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.


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


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)


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)


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.


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.


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,


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


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


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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