Heading Stress partitioning and wellbore failure in the West Tuna
Exploration Geophysics (2006) 37, 215–221
Stress partitioning and
wellbore failure in the
West Tuna Area,
Key Words: Gippsland Basin, wellbore
stress, finite element modelling
Image logs from the deep intra-Latrobe and Golden Beach
Subgroups of the West Tuna area in the Gippsland Basin reveal that
wellbore failure is restricted to fast, cemented sandstone units and
does not occur in interbedded shales. Triaxial testing and analysis
of empirically derived, wireline-log based strength equations
reveals uniaxial compressive strengths of 60 MPa in sandstones
and 30 MPa in shales in the West Tuna area. Conventional analysis
of wellbore failure assumes constant stresses in the shales and
adjacent sandstones and that breakout is focused in the weaker
units. We propose that the flat lying, strong, cemented sandstone
units in the West Tuna area act as a stress-bearing framework
within the present-day stress regime that is characterised by very
high horizontal stresses (SHmax > Shmin = Sv). Stress focusing in
strong sandstone units can result in high stress concentrations at
the wellbore wall and account for the restriction of wellbore failure
to the strong sandstone units.
Finite element methods were used to investigate the stress
distribution in horizontal, interbedded ‘strong’ sands and ‘weak’
shales subject to a high present-day stress state such as exists
in the West Tuna area (SHmax > Sv ~ Shmin). Modelling using the
present-day stress tensor and estimated elastic properties for
the sandstones and shales indicates that the present-day stress
is ‘partitioned’ between ‘strong’ inter-bedded sandstones and
‘weaker’ shales, with high stress being focussed into the strong
sandstones. The stress focusing causes borehole breakout in the
sands despite their higher strength. Conversely, stresses are too low
to generate wellbore failure in the weaker shales.
Stress magnitudes and orientations have been shown to vary
substantially between lithologies in petroleum fields (Warpinski
et al., 1985; Evans et al., 1989; Raaen et al., 1996). It has been
proposed that the variation in stress distribution through different
lithological units in a sedimentary basin (herein referred to as stress
partitioning) depends on relative rock strength and the present-day
stress state (Plumb, 1994; Reches, 1998). Plumb (1994) found
that the ratio of minimum to vertical present-day stress was
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Manuscript received 6 January, 2006.
Revised manuscript received
Exploration Geophysics (2006) Vol 37, No. 3
Fig. 1. Location of the West Tuna study area in the Gippsland Basin
40% greater in ‘hard’ carbonate rocks, and 20% higher in ‘hard’
sandstones, than in the ‘weak’ shales in sedimentary basins at high
present-day stress (reverse stress regimes). Similarly, the ratio of
minimum to vertical stress was found to be 4 to 15% higher in
‘weak’ shales than in ‘strong’ sandstones in basins in a relaxed
present-day stress state (normal fault regimes).
Although reliable methods have been developed for estimating
present-day stress in individual reservoirs using leak-off tests
during drilling or specialised injection tests (such as mini-frac
tests), these are often expensive and do not test all lithological
units intersected by the wellbore. As such, the present-day stress
tensor can often only be examined at a field or basin scale. The low
spatial resolution of stress data is a problem in the assessment of
wellbore stability and planning of fracture stimulation operations,
where the present-day stress tensor is required in both the reservoir
and surrounding non-reservoir units (Desroches and Woods, 1998;
Smith et al., 2001; Barree, 2004).
The interpretation of six image logs covering the deep intraLatrobe and Golden Beach Subgroups in the West Tuna area of
the Gippsland Basin (Figure 1) revealed that borehole breakout
occurs in strong, cemented sandstones and is absent in the weaker
shales. This is inconsistent with conventional wellbore stability
analysis, which tends to assume that wellbore failure occurs in
the ‘weaker’ units (Hickman et al., 1985; Zoback et al., 1993;
Reinecker and Lenhardt, 1999). This paper reviews the presentday stress in the Gippsland Basin and compares the relative
strengths of sandstones and shales from the deep intra-Latrobe and
Golden Beach Subgroups. Finite element modelling is then used to
show that the high present-day horizontal stresses that exist in the
Gippsland Basin may be partitioned to ‘strong’ lithological layers
and can account for the occurrence of breakout in the cemented
Stress partitioning Right
PRESENT-DAY STRESS IN THE WEST TUNA AREA
The orientation of 96 borehole breakouts (194 m in cumulative
length) and four drilling-induced tensile fractures (55 m in
cumulative length) interpreted from six image logs consistently
indicate that SHmax is oriented ~138°N in the West Tuna area. The
vertical stress magnitude was derived from density, sonic and
checkshot velocity data from the Tuna-4 exploration well and the
West Tuna-39 development well. The two vertical stress profiles
indicate that Sv is consistent across the West Tuna area, ranging
from 20 MPa at 1 km to 66 MPa at 3 km depth (Figure 2). The
lower bound to the leak-off pressures from deep intra-Latrobe and
Golden Beach Subgroups suggests that the minimum horizontal
stress gradient (Shmin) is ~20 MPa/km (close to Sv; Figure 2).
Modular Dynamic Test pressures indicate that pore pressure is
hydrostatic in the sandstones above 2800 m (Figure 2). The SHmax
magnitude can be constrained using observations of drillinginduced tensile fractures (DITFs) on image logs and the criterion
for formation of DITFs in elastic, impermeable rocks in vertical
wellbores (Peska and Zoback, 1995; Brudy and Zoback, 1999;
Nelson et al., 2005). Assuming the stress magnitudes defined
above, then the occurrence of DITFs in the West Tuna area
constrains the magnitude of SHmax to ~ 40 MPa/km (in sands above
2800 m). The present-day stress tensor suggests that the West Tuna
area is on the boundary between strike-slip and reverse faulting
stress regimes (i.e., SHmax > Sv ≈ Shmin; Figure 2).
Fig. 2. Stress–depth plot for the West Tuna area. The diamonds
represent the depths at which the stress gradients were assessed. Shmin
has been determined from leak-off tests (red data), Sv from density and
check–shot data (light green gradient from West Tuna-39, dark green
gradient from Tuna-4), SHmax from the occurrence of drilling-induced
tensile fractures (orange data) and Pp from MDT tests (blue data).
The orientation of SHmax in the West Tuna area is consistent
with previously determined orientations in the greater Gippsland
Basin and southeast Australia as a whole (Nelson and Hillis, 2005;
Nelson et al., 2006). The high present-day stress magnitudes
are also consistent with earthquake focal mechanisms and the
neotectonic record, including significant reverse faulting in
Southeast Australia (Nelson et al., 2006). The orientation of
the horizontal stress, and the high, present-day horizontal stress
magnitudes in the Gippsland Basin have been suggested to be a
consequence of contemporary oblique compression along the New
Zealand plate boundary (Coblentz et al., 1995; Sandiford, 2003;
Nelson et al., 2006).
ROCK STRENGTH IN THE WEST TUNA AREA
Knowledge of the compressive strength of rocks is important to
understanding wellbore failure in petroleum fields (Zoback et al.,
1985). The uniaxial compressive strength (UCS) of rocks can be
determined from laboratory testing of core samples or estimated
using empirical relationships based on wireline log data. Both of
these methods have been used in this study and are outlined in the
Laboratory testing of core
Fig. 3. Borehole breakout in a cemented sandstone interpreted on the
West Tuna-8 image log. Resistive features around the wellbore appear
white, conductive features appear brown or black. The track on the
right shows a dynamic presentation of the image log, while the track
on the left shows a static image. Note the low gamma ray count, fast
sonic velocity, and reasonably high density. The static image shows
true resistivity and indicates that the resistivity is quite high in the
Two laboratory strength measurements were available from
triaxial tests undertaken on the deep intra-Latrobe and Golden
Beach Subgroups in the West Tuna area (Nelson, 2002). These
sandstone units are characterised by low porosity, low permeability
(<5 mD), high resistivity, low gamma ray count ( ~ 60–70 gPI) and
a high sonic velocity (Δt = 60–85 µs/ft), which suggests that they
are cemented and likely to be hard and strong (Figure 3). Failure
envelopes constructed from the multi-stage triaxial test data
indicate that the sandstones have a cohesion (C) of ~ 13.5 MPa
and a co-efficient of friction (µ) of ~ 0.90 (Figure 4). The uniaxial
compressive strength (C0) is not directly measured in a triaxial test
but can be determined by substituting C and µ into equation (1)
below. Equation (1) indicates that the average uniaxial compressive
strength of the two sandstone samples is ~ 60 MPa:
C0 = 2C
2 + 1
Exploration Geophysics (2006) Vol 37, No. 3
Stress partitioning Right
Unfortunately no laboratory testing of UCS in shales
from the deep intra-Latrobe or Golden Beach Subgroups
was available in the Gippsland Basin. Triaxial test data
was available for one shale sample from the Lakes
Entrance formation ( ~ 2400 m depth; Figure 4). The
failure envelope derived from the triaxial test results
indicates a cohesion of ~ 8 MPa and a coefficient
of friction of 0.6. When these values are substituted
into equation (1) the uniaxial compressive strength is
determined to be ~ 30 MPa. Shales in the deep intraLatrobe and Golden Beach subgroups are characterised
by their high gamma count (> 100 gPI) and relatively
slow sonic velocity (Δt = 90–100 µs/ft). Analysis of
wireline log data over the sampled interval reveals that
the shale tested is (petrophysically) very similar to those
at depth (GR = 100 gPI, Δt = 90 µs/ft). Hence the shale
tested is believed to be representative of those observed
in the image logs in this study.
Fig. 4. Mohr circles and Mohr-Coulomb failure envelope from triaxial testing of
a cemented sandstone in the Golden Beach sub-group and a shale from the Lakes
Entrance formation. The sandstone sample has a µ approximately equal to 0.9, a
cohesive strength approximately equal to 13.5 MPa and a compressive strength of
60 MPa. The shale sample has a µ approximately equal to 0.6, a cohesive strength
approximately equal to 8 MPa and a compressive strength of 30 MPa.
Since only three UCS tests were available in the
Gippsland Basin, generic empirical relationships were
used to determine UCS from sonic logs in sands
and shales from three West Tuna wells. Log-based lithological
discrimination was based on gamma ray (GR), density (RHOB),
sonic velocity (DT) and caliper (CALI) logs. The logs were first
examined to determine if the lithology was coal (distinguished
by low DT, RHOB and GR), and if not the GR was used to
discriminate sandstone and shale. Sandstones were interpreted
where GR < 80 API, shales were interpreted where the GR
> 100 API. The sonic velocities from each lithology were then
substituted into the sand or shale empirical relationships:
where UCS is in MPa and Δt is in microseconds per foot (µs/ft).
An example UCS log from the West Tuna-39 development well is
shown in Figure 5.
The McNally (1987) equation was developed using strength
data from sandstones in a shallow coal field environment in
the Bowen basin however the range of UCS calculated using
the McNally equation for the intra-Latrobe and Golden Beach
sandstones was found to be ~ 59–147 MPa (average Δt = 60–
85 µs/ft) which compare very well to the laboratory derived values.
The Chang (2004) equation was based on a global shale data set
and determines the range of UCS for the intra-Latrobe and Golden
Beach shales to be ~ 24–32 MPa (average Δt = 90–100 µs/ft)
which is consistent with lab-derived UCS and verifies that shales
are much weaker than the sands in the West Tuna area.
STRESS DISTRIBUTION AT THE WELLBORE WALL
Borehole breakout forms when the circumferential stress at
the wellbore wall exceeds the compressive strength of the rock
(Peska and Zoback, 1995). From this perspective it is somewhat
counter-intuitive that breakout forms in the strong sandstones
rather than the weak shales in the West Tuna area (Figure 5).
The following sections outline the Kirsch equations that describe
stress concentration at the wellbore wall and wellbore failure.
We will show that shales would be expected to fail prior to sands
using a conventional Kirsch approach to wellbore stability in
the West Tuna area. Finite element methods are then used to
investigate stress variation by lithology (and rock strength) in a
Exploration Geophysics (2006) Vol 37, No. 3
high horizontal present-day stress environment such as exists in
the West Tuna area.
Stresses Around a Vertical Wellbore
As a well is drilled, the wellbore wall must support stresses
previously carried by the removed rock. This causes a stress
concentration about the borehole that depends on the orientations
of the wellbore and of the far field present-day stress (Kirsch,
1898; Jaeger and Cook, 1979; Amadei and Stephansson, 1997).
Three principal stresses act on the wall of a vertical well (Kirsch,
1898), these are:
the radial stress (σrr) which acts normal to the wellbore,
the axial stress (σzz) which acts parallel to the vertical
wellbore axis, and,
the circumferential stress (σθθ), which acts orthogonal to σrr
The stress at the wall of a wellbore drilled through elastic,
homogeneous and isotropic rock can be described by the Kirsch
(1898) equations. The magnitude of the stresses depends on the
magnitude of the far field stresses, the radius of the wellbore (R),
distance from the wellbore (r) and the pore pressure (Pp). For the
full Kirsch equations and a comprehensive description of wellbore
stresses, the reader is referred to Jaeger and Cook (1979). The
Kirsch equations may be simplified if only the stresses at the
wellbore wall are considered (i.e., where R = r). The simplified
Kirsch equations are described in Moos and Zoback (1990). The
Kirsch equation for circumferential stress at the wall of a vertical
well can be written:
= S ' H max + S 'h min 2 S ' H max S 'h min cos 2 P
where ∆P is the difference between mud pressure and pore pressure
(Pw-Pp), θ is the angle between the S′Hmax azimuth and north and S′Hmax
and S′hmin are effective stresses (Moos and Zoback, 1990).
If the circumferential stress is plotted with respect to position
around the wellbore wall (Figure 6) it can be shown that σθθ is
maximum when θ = 90° (i.e., at the azimuth of far-field Shmin),
circumferential stresses are calculated to be 0 and 80 MPa
respectively assuming mud-weight in the well is in balance with
the pore pressure (Pw = Pp). The uniaxial compressive strengths
determined for sandstones and shales in the West Tuna area
have also been plotted on Figure 7. Figure 7 illustrates that
borehole breakout is more likely in shales than in sandstones in
the West Tuna area if a conventional approach (which considers
a homogeneous stress distribution, independent of lithology) is
assumed. This is contrary to what is observed in the West Tuna
area. One possibility that explains the systematic occurrence of
borehole breakout in the strong sandstone units is that stress is
unequally distributed between different lithologies in the West
Tuna area. We next investigate the likelihood of this possibility
through finite element modelling.
Finite Element Modelling
A possible mechanism that explains the observed wellbore
failure in the West Tuna area is that present-day stress is higher in
the sandstone units than in the interbedded shales. Drilling-induced
tensile fractures and leak-off tests have been used to constrain the
present-day stress tensor in sandstones in the West Tuna area.
However, since no leak-off tests or wellbore failure exist in the
shales, there is no data on stress magnitude in the shales. A finite
element model was constructed to investigate the concept of stress
variation by lithology (stress partitioning), and to predict the
state-of-stress in the shales in the West Tuna area. Linear elastic
constitutive equations were used so that the results of the finite
element model could be directly compared with the conventional
approach to wellbore stability (using the Kirsch equations). Pore
pressure and mud-weight have been accounted for by assuming
an in-balance well and applying effective stresses at the model
boundaries. The finite element modelling presented herein is only
intended to investigate the concept of stress partitioning in the
West Tuna area and is not intended to be fully predictive.
Fig. 5. UCS log derived from sonic log data (blue), gamma ray log
(red) and interpreted borehole breakouts (black) from the West Tuna39 development well. The logs show that borehole breakout occurs in
sandstone (low GR) intervals with high compressive strength (high
The stress concentration around the wellbore in a single
sandstone layer predicted by the finite element code DIANA,
was verified against the Kirsch equations for stress concentration
around a vertical well. A 3D, linear elastic model of a wellbore
drilled in a homogeneous block was constructed (TNO
Construction Research, 2000). Structural boundary conditions
were defined by imposing displacement constraints at three
of the model boundaries (in the xy plane, yz plane and the zx
plane). The three effective principal stresses previously derived
(S'Hmax = 30, S'hmin = 10 and S'v = 10 MPa/km) were applied
perpendicular to the remaining three model boundaries. The
model boundaries were applied in this way to represent the high
horizontal present-day stresses in the West Tuna area due to
the compressional plate boundary at New Zealand. The model
boundaries were constructed approximately six well diameters
from the wellbore wall so that boundary effects were minimal.
The perturbed near-wellbore stress environment is generally
considered to extend three wellbore diameters from the well
(Fjær et al., 1992). A Poisson’s ratio of 0.25 and an elastic
modulus of 40 GPa are considered average values for sandstones
and were applied in the model construction (Lama and Vutukuri,
1978). The model geometry was discretised into elements using
meshing algorithms inbuilt in DIANA.
The present-day stress tensor determined in the West Tuna
area (SHmax = 40 MPa/km, Shmin = 20 MPa/km, Pp = 10 MPa/km)
can be substituted into equation (4) for all orientations around
the wellbore wall (Figure 7). The minimum and maximum
The modelled circumferential stress at the wellbore wall in a
homogeneous ‘sandstone’ reservoir is presented in Figure 8. The
modelled circumferential stress is consistent down the wellbore
and is a maximum of 80 MPa/km at the azimuth of Shmin (blue)
and a minimum of 0 MPa/km at the azimuth of SHmax (red). The
circumferential stresses at the wellbore wall calculated using the
finite element approach are consistent with those derived from the
Kirsch equations (Table 1 and Figure 7).
and minimum when θ = 0° (i.e., at the azimuth of far-field SHmax).
Equation (4) can therefore be simplified for the conditions where
θ = 0° and θ = 90° (Equations 5 and 6 respectively).
max = 3S H max S h min P
( = 90°) .
min = 3S h min S H max P
( = 0°) .
Borehole breakouts form due to shear failure at the wellbore
wall when the maximum circumferential stress around the wellbore
exceeds the compressive strength of the rock (Peska and Zoback,
1995; Barton et al., 1998). The circumferential stress is maximised
at θ = 90°, hence breakouts form in the wellbore at the azimuth
of Shmin (Figure 6). Equation (5) can be modified to represent the
criterion for formation of breakouts in elastic, impermeable rocks
in vertical wellbores such that:
max = 3S H max S h min P C0 ,
where C0 is the uniaxial compressive rock strength.
Using Conventional Methods to Assess Wellbore Failure
Exploration Geophysics (2006) Vol 37, No. 3
Stress partitioning Right
Fig. 6. Circumferential stress diagram showing that breakouts form when
the circumferential stress exceeds the compressive strength of the rock
and drilling induced tensile fractures form when the circumferential
stress is less than the tensile strength of the rock.
Fig. 8. Finite element model of circumferential stress
about a vertical wellbore drilled through homogeneous
rock. Blue represents high stress, red represents low
Fig. 9. a) 3D finite element model of interbedded sandstone and shales. The ‘sandstone’
layers (red) were assigned an elastic moduli of 40 GPa and a Poisson’s ratio of 0.25. The
shale layer (orange) was assigned an elastic moduli of 0.86 GPa and a Poisson’s ratio of
0.3. b) Circumferential stress at the wellbore wall derived from the finite element model.
Table 1. Far-field (total) stresses and circumferential stresses at the
wellbore wall in modelled sandstone and shale layers calculated using
Once the finite element code and methodology were verified
using the model above, a simplified 3D, linear elastic model of
a wellbore drilled through alternating strong ‘sandstone’ and
weak ‘shale’ layers was constructed (Figure 9a). The stress
boundary conditions were applied such that the present-day stress
tensor in the sandstone (in the far-field and at the wellbore wall)
was consistent with that determined previously (SHmax ~ 40 MPa/
km, Shmin ~ 20 MPa/km and Sv ~ 20 MPa/km; σθθmax = 80 and
σθθmin = 0). Based on Lama and Vutukiri (1978) the upper and
lower ‘sandstone’ layers were assigned a Poisson’s ratio of 0.25
and an elastic modulus of 40 GPa (red in Figure 9a). The middle
Fig. 7. Plot of circumferential stress and average compressive rock
strengths for sandstones and shales in the West Tuna area. Assuming a
conventional Kirsch model for wellbore failure (equivalent stresses in the
sandstone and shale); shales are more likely to fail than sandstones in the
West Tuna area.
Exploration Geophysics (2006) Vol 37, No. 3
‘shale’ layer was assigned a Poisson’s ratio of 0.35 and an elastic
modulus of ~ 10 GPa (orange in Figure 9a).
The results of the multilayer 3D finite element model are
shown in Figures 9b and 10 and support the hypothesis that the
stress may be partitioned between stronger ‘sandstone’ units
and adjacent shales. The present-day stress is focused in the
sandstones, where horizontal, interbedded, lithologies of varying
strengths are subjected to high present-day horizontal stresses.
The modelled ‘sandstone’ units are at high stress equivalent to the
total far-field tectonic stress (SHmax = 40 MPa and Shmin = 20 MPa;
Table 1) whilst the total stress in the shale prone units is lower
(SHmax = 20 MPa and Shmin = 15 MPa; Table 1). This mechanism
for stress ‘partitioning’ is analogous to stiff boards separated by
sponge in a vice. The ‘strong’ units (sandstones) take up the stress
‘load’ whilst the sponge (shale) remains relatively unstressed and
IMPLICATIONS FOR WELLBORE STABILITY
The finite element modelling of interbedded sandstones and
shales shows that where far-field stress is low in the shales,
the stress concentration at the wellbore wall is low (and more
isotropic). Low stress concentration and low stress anisotropy
a northeast–southwest (σh) azimuth as shown in Figure 11. The
stresses acting on a horizontal well deviated in the southeast–
northwest (σH) azimuth are isotropic and hence this is a relatively
stable drilling trajectory. The risk of breakout formation in
the shale is low in all directions because of the lower stress
anisotropy in the shales.
Fig. 10. Circumferential stress in the a) sandstone units and b) shale
units derived from petroleum data and finite element modelling. The
circumferential stress at the wellbore wall in the sandstone exceeds the
compressive strength of the sandstone that should result in the formation
of borehole breakout. Conversely, the circumferential stress in the shale
does not exceed the compressive strength in the shale and hence no
borehole breakout would be expected.
Conventional analysis of wellbore failure (assuming constant
stress in all lithologies) predicts that borehole breakout occurs in
weak shales rather than strong sandstones in the West Tuna area
of the Gippsland Basin. However, analysis of image logs has
revealed that wellbore failure only occurs in strong, cemented
sandstones in the West Tuna area. Rock strength testing and
sonic log-derived uniaxial compressive strengths suggest that
sandstones are much stronger than shales in the West Tuna
area. A finite element model of horizontal, interbedded, ‘strong
sandstones’ and ‘weak shales’ was constructed and subjected to
a high horizontal far-field present-day stress load equivalent to
that believed to exist in the Gippsland Basin. The model revealed
that ‘strong’ sandstones act as a stress-bearing framework
when subjected to high horizontal stresses. The sandstone units
effectively ‘shield’ the shale-prone (‘weak’) sections from the
high horizontal stress load resulting in the shales being at a much
lower and less anisotropic stress state than the sandstones.
Stress partitioning (higher stress in the sandstones relative to
the shales) results in high stress concentrations at the wellbore
wall in the sandstones whilst the stress concentrations in the
shales are much lower. We suggest this mechanism accounts
for the high degree of borehole breakout in the sandstones, and
absence of borehole breakout in the shales of the Latrobe Group
and Golden Beach Subgroups in the West Tuna area.
Fig. 11. Breakout risk diagrams constructed using the analytically
determined present-day stress tensor in the sandstone (SHmax
orientation = 138°N, SHmax ~ 40 MPa/km, Shmin ~ 20 MPa/km and
Sv ~ 20 MPa/km), and the modelled stress tensor in the shale (SHmax
orientation = 138˚N, SHmax ~ 16 MPa/km, Shmin ~ 14 MPa/km and
Sv ~ 15 MPa/km). Red indicates high risk of breakout, blue indicates low
risk of breakout.
decreases the propensity for wellbore failure during drilling (Figures
9b and 10). Assuming breakouts develop when the maximum
circumferential stress exceeds the uniaxial compressive strength of
the rock, then the finite element model suggests that the propensity
for breakout is high in the ‘sandstone’ (where σθθmax ~ 80 MPa/km)
and lower in the ‘shale’ (where σθθmax ~ 25 MPa/km). The contrast
in circumferential stress between the modelled strong ‘sandstones’
and weak ‘shales’ can explain the occurrence of wellbore failure
in the strong lithologies in the West Tuna area and the absence of
wellbore failure in the weaker shale-prone lithologies (Figure 10).
The modelling suggests that optimum mud weights to prevent well
collapse for drilling should be planned considering the present-day
stress in the sandstone units.
The finite element modelling undertaken herein illustrates
that different lithological units may behave differently under
an applied tectonic stress load. Hence, lithology should be
considered when assessing wellbore failure on image logs, and
indeed when using petroleum wellbore data such as injection
tests for present-day stress analysis. Field and basin scale
present-day stress tensors should be treated with caution during
well planning or other operations which require knowledge of
the present-day stress tensor (e.g., hydraulic fracturing or waterflooding).
The authors thank Glen Nash, Michael Power, Adem Djakic,
and Wayne Mudge (ExxonMobil) for supplying image log data
and providing useful insight. Mark Tingay and Mike Dentith
are thanked for their comments, which greatly improved the
manuscript. Wilde FEA Ltd is thanked for the use of DIANA and
the ASEG RF for supporting Emma Nelson’s PhD project.
The risk of breakout development in wells of all orientations
can be assessed in terms of the rock strength (compressive strength,
C0) required to prevent breakout formation normalised to Sv and the
present-day stress tensor (Brudy and Zoback, 1999; Figure 11). A
breakout risk diagram has been constructed using the present-day
stress tensor determined analytically in the sandstones and the stress
tensor derived from the finite element modelling in the shales in
the West Tuna area. Blue colours indicate that low rock strength
(or low mud weight) is required to prevent breakout. Red colours
indicate that high rock strength (or high mud weight) is required to
prevent breakout. The risk of breakout formation in the sandstones
in West Tuna is greatest for a vertical well and for wells deviated in
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