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1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
9Stress analysis, fault reactivation and fault seal integrity in the Bight BasinSD Reynolds1, RR Hillis1 and GW O’Brien1
1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
INTRODUCTION . . . . . . . . . . . . . . . . . . . 2
EMPIRICAL EVIDENCE FOR FAULT SEAL
FAILURE IN THE BIGHT BASIN . . . . . . . . 2
METHODOLOGY FOR EVALUATING FAULT
REACTIVATION IN THE BIGHT BASIN . . . 6
IN SITU STRESS IN THE BIGHT BASIN . . 9
Stress orientations . . . . . . . . . . . . . . . . . . .9
Vertical stress magnitude . . . . . . . . . . . . .11
Minimum horizontal stress magnitude . . . .14
Maximum horizontal stress magnitude . . . .17
Pore pressure . . . . . . . . . . . . . . . . . . . . .19
RISKING FAULT REACTIVATION AND SEAL
INTEGRITY . . . . . . . . . . . . . . . . . . . . . 20
FAULT REACTIVATION AND SEAL
INTEGRITY IN THE BIGHT BASIN . . . . . 22
IMPLICATIONS FOR EXPLORATION
PROSPECTIVITY . . . . . . . . . . . . . . . . . 25
REFERENCES . . . . . . . . . . . . . . . . . . . 34
FIGURES
9.1 Location map, Great Australian Bight. . 3
9.2 Basin boundaries and well locations in
the eastern region of the Great Australian
Bight . . . . . . . . . . . . . . . . . . . . . . . . 4
9.3 Seismic line through the breached trap
tested by Jerboa 1 in the Eyre Sub-basin,
western Bight Basin . . . . . . . . . . . . . 5
9.4 Earthquake data in the Great Australian
Bight region, provided by D Love
(PIRSA). . . . . . . . . . . . . . . . . . . . 7,8
9.5 Circumferential stress around an open,
vertical well-bore . . . . . . . . . . . . . . 10
9.6 FMS image log from Greenly 1 showing
borehole breakout along two opposing
pads . . . . . . . . . . . . . . . . . . . . . . . 11
9.7 Stress map of the Bight Basin showing
A–D quality stress indicators . . . . . . 13
9.8 Rose diagram showing the SHmax
orientations determined from individual
breakouts from the Bight Basin . . . . 14
9.9 Australian stress map (A–D quality) with
the new Bight Basin stress data . . . . 15
9.10 Vertical stress magnitudes from mean
sea level for the Bight Basin . . . . . . 16
9.11 Effective vertical stress magnitudes from
seabed for the Bight Basin. . . . . . . . 16
9.12 Effective stress-depth plots for the Bight
Basin . . . . . . . . . . . . . . . . . . . . . . 18
9.13 An example plot of total stress versus
depth for a water depth of 400 m . . 21
9.14 Stress-depth plot showing mud weights
used in each well and RFTs in Jerboa 1
and Greenly 1 . . . . . . . . . . . . . . . . 23
9.15 FAST map of two fictitious faults using
the stress field in Case I . . . . . . . . . 24
9.16 Risk of fault reactivation . . . . . . . . . 26
9.17 Location map of the Great Australian
Bight showing Sea Lion (Late Jurassic)
and Tiger (Late Cretaceous) fault poly-
gons (after Totterdell et al., Ch. 4) used
in the fault reactivation risks analysis 27
9.18 Fault reactivation risks calculated using
FAST technique for Case I (strike-slip
stress regime) . . . . . . . . . . . . . . . . 28
9.19 Fault reactivation risks calculated using
FAST technique for Case II (strike-slip-
normal stress regime) . . . . . . . . . . . 29
9.20 Fault reactivation risks calculated using
FAST technique for Case III (normal
stress regime) . . . . . . . . . . . . . . . . 30
9.21 Regional map showing Sea Lion and
Tiger fault polygons (after Totterdell et al.,
Ch. 4) along regional tectonic elements,
plotted with wells, earthquake epicentres
and SAR slicks . . . . . . . . . . . . . . . . 321 Australian School of Petroleum, University of Adelaide, Adelaide SA 5005
email: [email protected], mailto:[email protected], mailto:[email protected]
2 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
INTRODUCTIONThe Bight Basin is located along the southern margin of
Australia within the Great Australian Bight (Fig. 9.1) and
developed as a Jurassic–Cretaceous rift. It is a genuinely
frontier petroleum exploration province which extends east–
west for ~1000 km, and north–south from the onshore
to the abyssal plain. A full description of the Bight Basin’s
physiography and tectonic development is provided in
Totterdell et al. (Ch. 4). Broad-scale, regional geophysical
surveying and limited drilling have revealed that the central–
eastern part of the basin contains four principal depocentres,
namely the Ceduna, Duntroon, Eyre and Recherche Sub-
basins (Fig. 9.2). Two thin platforms, the Madura and
Couedic Shelves, are located along the northern and eastern
margins of the basin. To date, only 10 exploration wells
have been drilled within the Bight Basin (Fig. 9.2), and
none of the results known to date proved a commercial
hydrocarbon accumulation.
The frontier nature of the Bight Basin means that, by
definition, identifying the principal exploration uncertainties
in the region is difficult. This chapter provides a broad
overview of the stress field within the Bight Basin, and
investigates the risk that assorted fault arrays within the
sub-basins will undergo sufficient structural reactivation
to induce fault seal failure. Issues of fault seal and fault
seal failure relating to shale smear and fault gouge are not
considered in this chapter, nor are the different rheological
properties of the faulted rocks taken into account.
EMPIRICAL EVIDENCE FOR FAULT SEAL FAILURE IN THE BIGHT BASINTo date, there has been almost no work published on fault
reactivation within the Bight Basin. Nevertheless, a number
of observations indicate that the issue of fault seal integrity
may represent a key exploration risk.
Work by Ruble et al. (2001) on the Jerboa 1 well in the
Eyre Sub-basin (Fig. 9.2) demonstrated the presence
of a 15 m thick palaeo-oil column within Callovian to
Kimmeridgian sands. These workers proposed that Jerboa 1
(Fig. 9.3) was charged, probably from a Late Jurassic –
Early Cretaceous petroleum system, but was then breached
during a period of structural reactivation during the Late
Cretaceous. Ruble et al. also noted that additional vertical
migration of hydrocarbons into the Tertiary sequences
may have occurred subsequent to this Late Cretaceous
breaching. They invoked the far-field effects of the collision
of the Australian and Asian Plates in the Late Tertiary as a
possible driving mechanism for this vertical migration.
Whilst the breaching of the trap at Jerboa 1 provides
unequivocal evidence of seal failure, several other empirical
indicators of seal failure are present throughout the Bight
Basin. These include the presence of numerous gas
chimneys within the Duntroon and Ceduna Sub-basins,
some of which correlate spatially with water column
geochemical ‘sniffer’ anomalies (see O’Brien et al., Ch. 10),
and the mapping of oil slicks across the Bight Basin using
3 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
40°
30°
130°120° GA 23/OA/1453
EUCLA
BASIN
BIGHT BASIN
OTWAY
BASIN
POLDA
BASIN
Western Australia South Australia
500 km
200054_039
Denmark Sub-basin
Bremer Sub-basin
EUCLA
BASIN
Synthetic Aperture Radar (SAR) data (Struckmeyer et al.,
2002; O’Brien et al., Ch. 10). Other indicators include the
well-known presence of asphaltite strandings in the region
(Sprigg and Wooley, 1963; Edwards et al., 1998; O’Brien
et al., Ch. 10) and colloquial ‘evidence’ for a relationship
between the timing of earthquakes and the occurrence of
major strandings in the area.
Figure 9.1 Location
map, Great Australian
Bight. Older basins are
shown superimposed
over younger basins.
Post-rift reactivation faults can extend quite close to the
sea floor in parts of the Bight Basin, which again indicates
that the risk of fault seal failure in these areas should be
investigated.
Earthquake data provide an empirical measure of how
tectonically stressed a basin is, and hence indirectly, how
4 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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Figure 9.2 Basin boundaries and well locations in the eastern region of the Great Australian Bight.
5 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
200054_065
Jerboa 1
14/OA/1551
SENW
Bronze Whaler
Southern Right
Minke
Sea Lion
White Pointer
Dugong
Wobbegong
Blue Whale
Two
-way
tim
e(s
)
2
1
10 km
3
0
Figure 9.3 Seismic line
through the breached trap
tested by Jerboa 1 in the Eyre
Sub-basin, western Bight
Basin. Reactivation faults stop
at the base of the Tertiary.
(After Totterdell et al. Ch. 4).
6 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
likely fault reactivation is to occur. Overall, the Bight Basin
does not appear to be particularly active seismically at the
present day, though this could be at least in part related to
a paucity of recording stations. Nevertheless, earthquake
activity has been recorded in the Bight Basin (Figs 9.4a, b).
The earthquakes are typically focused in the eastern Bight
Basin, within the Duntroon and eastern Ceduna Sub-basins,
and appear to be bracketed by the Eastern and Western
Accommodation Zones of Stagg et al. (1990), though
whether this is coincidental or real is not known at this
stage. Most of the earthquakes are shallow, with epicentres
within the upper 10 km of the sedimentary section, and
many are within the top 5 km, well within the syn- or
post-rift sections (Fig. 9.4a). Magnitudes are typically in
the range 2 to 3.5 (Fig. 9.4b), though an earthquake with
a magnitude of 4.6 was recorded on the Couedic Shelf in
1986. A series of earthquakes was recorded along the far
southern edge of the Recherche Sub-basin, in the Western
Australian part of the Bight Basin, between 1961 and
1995. These had magnitudes ranging between 4.2 and 5.2
and were located to the south and southeast of the Bremer
Sub-basin.
METHODOLOGY FOR EVALUATING FAULT REACTIVATION IN THE BIGHT BASINFault reactivation within the in situ stress field has been
demonstrated to control leakage of hydrocarbons from the
sub-surface in a number of regions around the world. For
example, trap breaching in the North Sea (Gaarenstroom
et al., 1993), the Gulf of Mexico (Finkbeiner et al., 2001)
and the Timor Sea (Hillis, 1998; Mildren et al., 2002) has
been related to faulting and fracturing associated with the
in situ stress field. In this chapter, the in situ stress field has
been evaluated and the relative attendant risk of reactivation
of faults with different orientations and dips in the Bight
Basin determined, in order to provide an overview of this
risk at a basin-scale. Using the in situ stress characteristics,
the likelihood of fault seal breach at prospect scale can
be better assessed once depth-converted fault geometries
are available from seismic interpretation. Assessing fault
reactivation at a regional scale can follow similar principles,
but more care should be exercised in evaluating the
reactivation risk, as more uncertainty is placed on the results
when basing the interpretation on just one set of parameters
averaged and extrapolated over large areas.
The key step in determining the risk of fault seal breach
due to fault reactivation within the in situ stress field is
determining the in situ stress field itself. The in situ stress
field was determined from assessing the drilling and logging
data acquired from the nine open-file exploration wells
which have been drilled in the Bight Basin (Reynolds et
al., 2003). Of these nine wells, six are clustered in a tight
group within the Duntroon and eastern Ceduna Sub-basins.
In order to gain a better understanding of the regional stress
field in the region, additional wells from the adjacent Polda
7 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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Figure 9.4(a) Earthquake data in the Great Australian Bight region — Earthquake depths (km). (Data provided by D Love, PIRSA.)
8 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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1�(����)����%�������&�.���� 2
Figure 9.4(b) Earthquake data in the Great Australian Bight region — Earthquake magnitudes. (Data provided by D Love, PIRSA.)
9 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
Basin were included in this study. Interpolations were also
made from the wider Australian Stress Map database <http:
//www.ncpgg.adelaide.edu.au/asm/>.
The water depth across the Bight Basin varies from
<100 m on the shelf to >5000 m in the deepest parts of
the Recherche Sub-basin. This variation poses a significant
problem when attempting to analyse the in situ stress field
for the entire basin. To overcome the problem associated
with water depth, effective stress (total stress minus pore
pressure) has been used in this study, instead of the total
stress, which is more typically used.
In this section, the in situ stress field within the Bight Basin
is first determined, and then the methodology for risking
fault reactivation and associated seal breach is described.
Finally, the implications for fault trap integrity within the
Bight Basin are summarised.
It should be noted that the in situ stress field determined
herein for the Bight Basin has implications beyond those
just for fault seal integrity. The stress field can affect
reservoir drainage patterns, fluid flow in fractured reservoirs,
hydraulic fracture simulation and well-bore stability,
especially in deviated wells (Hillis et al., 2000).
IN SITU STRESS IN THE BIGHT BASIN
Stress orientations
The maximum horizontal stress (SHmax
) orientation in the
Bight Basin was determined by interpreting borehole
breakout directions in 4-arm dipmeter (HDT) logs from four
wells and image log data (Formation Microscanner, FMS)
from two wells. Borehole breakouts are intervals where
the cross-sectional shape of the well-bore is elliptical due
to failure of the well-bore wall. The presence of an open
well-bore disturbs the sub-surface stress field, and the
circumferential, or hoop stresses, acting around the wall
of a vertical well-bore are maximised at the azimuth of the
minimum horizontal stress (Shmin
). If the circumferential
stress exceeds the compressive strength of the rocks forming
the well-bore wall, shear fractures form in the well-bore
wall (Fig. 9.5). Breakouts are created when these shear
fractures coalesce, causing rock to spall off the borehole
wall. In vertical boreholes, the orientation of the long axis of
a breakout yields the Shmin
direction. SHmax
is orthogonal to
the orientation of the breakouts.
Identification of breakouts from the 4-arm dipmeter tool
was done using rules based on the criteria set out by Plumb
and Hickman (1985). Only wells with deviations of <10°
were used. Wells with deviations >5° were checked for
key seating. HDT data were used to interpret borehole
breakouts in four wells, namely Echidna 1 (Duntroon Sub-
basin), Duntroon 1 and Platypus 1 (Ceduna Sub-basin), and
10 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
A total of 78 breakouts with a combined length of 1208 m
were interpreted in the six wells analysed. The breakouts
covered a depth range from 1460 to 4791 m below rotary
table. Mean SHmax
orientations inferred from these analyses
are presented in Table 9.1 and Figure 9.7. The average SHmax
orientation calculated from the six wells is 130°N. As would
be expected, more breakouts, and of a more consistent
orientation, can be interpreted on the image logs from
Greenly 1 and Borda 1 than on the dipmeter logs from the
other wells. The SHmax
orientations inferred from Greenly 1
and Borda 1 are considered the most reliable orientations for
this study and hence have been given an ‘A’ quality ranking.
The dominance of the northwest to southeast SHmax
trend in
the area is clear in Figure 9.8.
The newly interpreted Bight Basin data are plotted along
with the Australian stress field in Figure 9.9. This figure
emphasises the poor data coverage over much of the
Great Australian Bight. Stress orientations could only be
determined for the wells that are located on the eastern side
of the Bight Basin, that is within the Duntroon and eastern
Ceduna Sub-basins, and also within the Polda Basin. The
average SHmax
orientation of 130°N for the available wells
in the Bight Basin is consistent with SHmax
orientations
in the Otway Basin further to the east (Fig. 9.9). Stress
trajectories (which are essentially regionally averaged
stress orientations) for the Australian stress field have been
calculated by Hillis and Reynolds (2000) and plotted in
Figure 9.9 in order to obtain a better understanding of
Shmin
Shmin
SHmaxSHmax
bit size
breakout spall zone
compressive strength
Circ
umfe
rent
ial s
tres
s
Orientation with respect to SHmax
0°
0
-90° 90°
200054-019
Figure 9.5
Circumferential stress
around an open,
vertical well-bore.
Schematic cross-section
of a borehole breakout
also shown. Breakouts
form where the
circumferential stress
exceeds compressive
rock strength.
Columbia 1 (Polda Basin). Schlumberger’s FMS tool was
run in both the Greenly 1 and Borda 1 wells in the eastern
Ceduna Sub-basin. Breakouts on image logs appear as
relatively wide, ‘blobby’ zones of low resistivity where the
well-bore has been subjected to spalling (Fig. 9.6). Image
log data yields a more confident interpretation of the SHmax
orientation than the identification of breakouts obtained
solely from dipmeter logs. All orientations used in this
study have been corrected for magnetic declination. The
mean SHmax
orientation determined in each of the wells was
quality-ranked using the World Stress Map scheme (Zoback,
1992).
11 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
the regional stress field over the entire Bight Basin. The
previously calculated stress trajectories on the eastern side
of the Bight Basin are consistent with the SHmax
orientation
determined from the wells in the region, for example in
the western Otway Basin immediately to the east. On the
western side of the Bight Basin, the stress trajectories
indicate a more east–west orientation, which reflects the
(data constrained) east–west SHmax
orientation in the Perth
region to the west (Hillis and Reynolds, 2000; Reynolds
and Hillis, 2000). Due to the lack of available data in the
western Bight Basin, it was not possible to verify if the
SHmax
orientation rotates to an east–west orientation in the
western part of the Bight Basin. As such, the average SHmax
orientation of 130°N was used for the entire Bight Basin.
Additional drilling in the western Bight Basin would allow
the true stress orientations in that area to be determined.
Vertical stress magnitude
The vertical, or overburden stress (Sv) at a specified depth
can be equated with the pressure exerted by the weight of
the overlying rocks and expressed as:
Sv = , 1
where ρ(z) is the density of the overlying rock column at
depth z, and g is the acceleration due to gravity.
Hence, it is necessary to know the density of the rock
column in order to determine the magnitude of the vertical
Figure 9.6 FMS image log
from Greenly 1 showing
borehole breakout along
two opposing pads. The
breakout is orientated
approximately 40°N and
220°N, indicating a SHmax
orientation of 130°N.
4462
4463
4464
4465
4466
Breakout Breakout
200054-020
Dep
thin
met
res
12 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
stress. Since Dickson’s (1953) classic paper on Gulf Coast
pressure, it has been commonplace to adopt a value of
2.3 g/cm3 for the mean density of sedimentary rocks. The
popularity of this value is partly due to the fact that the
resulting overburden pressure gradient is 1.0 psi/ft (22.6
MPa/km). However, where density data are available for
the rock column, this value should not be assumed since
density, and hence vertical stress gradient, varies both
between different basins, and with depth in the same basin.
Vertical stress magnitudes were determined using density
log data for a total of 10 wells in the Bight and Polda
Basins. Vertical stress calculations require that the density
log be integrated from the surface (here sea level, assuming
the water column has a density of 1.03 g/cm3). However,
the density logs are not commonly run from the surface. The
average density from the surface to the top of the density log
run can be estimated by converting check-shot velocity data
to density using the Nafe-Drake velocity/density transform
(Ludwig et al., 1970).
The vertical stress profiles for the ten wells are shown in
Figure 9.10. Jerboa 1 and Potoroo 1 have significantly lower
vertical stress magnitudes for a given depth than the other
eight wells. This is due to the difference in water depth
between Jerboa 1 (760 m water depth), Potoroo 1 (252 m)
and the rest of the wells (<155 m). In order to account for
the variation in water depth, the vertical stress profiles have
been calculated as effective vertical stress (Sv’) assuming
normally pressured sediments (Fig. 9.11). The effective
vertical stress in the Bight Basin is closely approximated by
the power law function:
Sv’ = 10.46 z 1.179, 2
where effective vertical stress is in MPa and z is depth in
kilometres below seabed.
* No. is the total number of breakouts in a well.
† Azi and SD are the mean SHmax
orientation of breakouts in a well, and their standard deviation in degrees as determined by circular statistical analysis.
‡ Q is the quality rating of the mean SHmax
orientation in the well following the World Stress Map scheme (Zoback, 1992).
Table 9.1 Summary of
breakout analyses in
the Bight and Polda
Basins
Well Log Location No.* Depth (m) Unweighted Length weighted
Latitude Long. Top Bot. Azi† SD† Q‡ ∑length
(m)
Azi† SD† Q‡
Borda 1 Image -35.845 135.687 22 2464 2742 141 5 A 45 141 4 A
Duntroon 1 Dipmeter -35.591 135.350 4 1965 3190 098 34 D 392 099 12 A
Greenly 1 Image -35.479 134.930 21 4101 4791 133 11 A 44 131 6 A
Echidna 1 Dipmeter -35.604 135.620 11 1551 3234 130 28 D 275 140 34 D
Platypus 1 Dipmeter -35.419 134.824 15 1801 3298 096 45 E 233 126 43 E
Columbia 1 Dipmeter -33.494 133.885 5 1460 2105 144 11 B 219 145 7 B
Bight and Polda Basins 78 1460 4791 132 25 1208 123 35
13 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
130° 134°
-30°
-34°
200054-021
0 200
KILOMETRES
Jerboa 1
Apollo 1
Potoroo 1
Method:breakouts
Regime:
Quality:
Figure 9.7 Stress map of the Bight
Basin showing A–D quality stress
indicators. Orientation of vector
represents the SHmax
orientation and
length of vector represents the data
quality. Wells with no data or E quality
data are represented by a dot.
14 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
200054-022
mean = 132°
stdev = 25°
number = 78
mean = 118°
stdev = 32°
total length = 1208 m
0 25 0 350
Figure 9.8 Rose
diagram showing the
SHmax
orientations
determined from
individual breakouts
from the Bight Basin.
(a) Unweighted. (b)
Length weighted.
As is seen in most basins worldwide, there is variation in the
vertical stress gradient with depth. This increase in vertical
stress gradient with depth is related to increased rock
density with depth due to sediment compaction. Note that
the commonly assumed vertical stress gradient of 1.0 psi/ft
(22.6 MPa/km) only applies at a depth of ~2.8 km below
the seabed in the Bight Basin.
Minimum horizontal stress magnitude
The most reliable determinations of minimum horizontal
stress (Shmin
) are yielded by hydraulic fracture tests. In
such tests, a tensile fracture is opened in a vertical well
by increasing the fluid pressure within an isolated section
of the well-bore. The fluid pressure at which the hydraulic
fracture closes provides a direct estimate of Shmin
, based
on the assumption that the fluid is holding the fracture
open against the least principal stress. Unfortunately,
hydraulic fracture tests are not widely undertaken during
exploration drilling. However, leak-off tests (LOT), in which
the pressure at which a fracture opens is determined, are
undertaken routinely. Leak-off pressures do not yield as
reliable estimates of Shmin
as fracture closure pressures. This
is largely because the leak-off pressure is controlled by the
disturbed stress field at the well-bore wall and because the
15 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
0 500
KILOMETRES
Method:
focal mechanism
breakouts
overcoring
hydro. fractures
geol. indicators
Regime:
Quality:
200054-023
Figure 9.9 Australian
stress map (A–D quality)
with the new Bight Basin
stress data included. Stress
trajectory map from Hillis
and Reynolds (2000) has
been plotted to highlight
the regional trends across
the Australian continent.
The SHmax
orientation for the
Bight Basin is reasonably
consistent with the stress
trajectories in the region.
16 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
200054-025
Dep
th b
elo
w s
eab
ed
in
metr
es
1000
Effective Stress in MPa
40200
0 60 80
2000
3000
4000
5000
8 MPa/km
Sv’ depthfunction
14 MPa/km
Jerboa 1Potoroo 1Borda 1
Duntroon 1Echidna 1
Greenly 1Platypus 1Columbia 1Gemini 1Mercury 1
Figure 9.11 Effective vertical stress magnitudes from seabed for the Bight Basin. A
power law function has been used to approximate the effective vertical stress.
Figure 9.10 Vertical stress magnitudes from mean sea level for the Bight Basin.
200054-024
Stress in Mpa
0
Jerboa 1Potoroo 1Borda 1
Duntroon 1Echidna 1
Greenly 1Platypus 1Columbia 1Gemini 1Mercury 1
Dep
thin
metr
es
(belo
wseale
vel)
5000
12 MPa/km 24 MPa/km
0
1000
2000
3000
4000
12020 40 60 80 100
17 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
leak-off pressure must overcome any tensile strength of
the formation. Nevertheless, it is widely accepted that the
lower bound to leak-off pressures in vertical wells gives a
reasonable estimate of Shmin
(e.g. Bell, 1990; Breckels and
van Eekelen, 1982).
Seven LOT pressures were performed in four wells over
the Bight region. Inspection of a number of reported LOTs
revealed that they were formation integrity tests in which no
fracture developed, and hence from which no information on
stresses could be inferred. The reliable LOT pressures were
plotted along with the formation integrity tests as effective
stress magnitudes in order to compare wells in varying water
depths. The lower bound to the effective pressures from the
LOTs suggests that the effective minimum horizontal stress
(Shmin
’) gradient is ~6 MPa/km. Due to the lack of leak-off
data, especially below 2000 m, the Shmin
’ gradient for the
Bight Basin cannot be constrained well. Nevertheless, it is
clear from the results obtained that the magnitude of Shmin
’
is less than that of Sv’ (Fig. 9.12). Hence, the Bight Basin
is in either in a strike-slip faulting (Shmin
’ < Sv’ < S
Hmax’) or
normal faulting (Shmin
’ < SHmax
’ < Sv’) stress regime.
Maximum horizontal stress magnitude
The magnitude of SHmax
is generally the most difficult
component of the stress tensor to determine. Many of the
methods commonly applied for constraining SHmax
could
not be applied in the Bight Basin due to a lack of relevant
data. The occurrence of borehole breakouts and drilling-
induced tensile fractures could not be utilised to constrain
SHmax
because drilling-induced tensile fractures were not
present in the image logs and rock strength data were not
available. Hydraulic fracture test-based techniques could
not be applied because no extended leak-off tests or mini-
fracture tests have been undertaken. Nevertheless, based on
the frictional limits to stress beyond which faulting occurs,
broad limits can be placed on SHmax
.
The magnitude of the effective maximum horizontal stress
(SHmax
’) was calculated in order to remove the effect of the
water depth. The magnitude of SHmax
’ can be constrained
by assuming that the ratio of the maximum to minimum
effective stress cannot exceed that required to cause faulting
on an optimally oriented, pre-existing fault (Sibson, 1974).
The frictional limit to stress is given by:
, 3
where µ is the coefficient of friction on an optimally oriented
pre-existing fault, S1’ is the effective maximum principal
stress and S3’ is the effective minimum principal stress.
For a typical value of µ = 0.6:
3.12. 4
2
2
'
3
'
1)1( �� ���
S
S
18 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
200054-026
Dep
th b
elo
w s
eab
ed
in
metr
es
Effective Stress in MPa
00 20 10040 60 80
� = 0.6
1000
2000
3000
4000
5000
LOT
FIT
S’hmin
S’v
S’Hmax
Figure 9.12 Effective stress-depth plots for the Bight
Basin. Shmin
’ is represented by the lower bound to
effective pressures from leak-off tests and SHmax
’ has been
determined from frictional limits. Sv’ has been calculated
using the power function described by Equation 2.
19 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
This relationship can be used to estimate the magnitude
of SHmax
’ in seismically active regions (Zoback and Healy,
1984) and provides an upper bound to SHmax
’ in relatively
seismically passive regions such as the Bight Basin.
In the Bight Basin, Shmin
’ is less than the Sv’; hence S
hmin
= S3’. The frictional limits to S
hmax’ have been determined
following Equation 4 and are shown in Figure 9.12,
assuming normally pressured sediments. The maximum
Shmax
’ gradient, based on frictional limits, is 18.7 MPa/km.
As a consequence, the region may be in a strike-slip faulting
(Shmin
’< Sv’ < S
Hmax’) stress regime. A normal faulting (S
hmin’
< SHmax
’ < Sv’) stress regime cannot be ruled out, however,
due to the lack of data constraining the magnitude of SHmax
’.
Consequently, in our analysis of fault reactivation/seal
breach risk, three cases (Table 9.2) have been considered:
I strike-slip faulting (Shmin
’< Sv’ < S
Hmax’) stress regime
II normal faulting (Shmin
’ < SHmax
’ < Sv’) stress regime
III boundary of strike-slip and normal faulting stress regimes.
The magnitude of the in situ stress field for the three cases
was determined at a depth of 1000 m below seabed.
Figure 9.13 shows as an example a total stress versus depth
plot for a case with a water depth of 400 m, using the
determined effective stresses and assuming hydrostatic pore
pressure. The total and effective stress magnitudes have
been listed for a depth of 1400 m in Table 9.3.
Pore pressure
Pore pressure measurements were only conducted in two
wells in the region. Jerboa 1, located in the Eyre Sub-
basin in the western Bight Basin, had two reliable repeat
formation tests (RFT), whereas Greenly 1, in the eastern
Ceduna Sub-basin, had 20 reliable RFTs (Fig. 9.14). In the
upper section of the two wells, the RFTs indicate hydrostatic
pore pressure. Below 3600 m, the RFTs in Greenly 1
indicate the presence of mild overpressure. In order to obtain
a better understanding of the pore pressure distribution,
the mud weights have been considered as a proxy for pore
pressure (Fig. 9.14). In general, the mud weights indicate
that most of the region is normally pressured. However, the
mud weights were elevated at approximately 3600 m in
both Greenly 1 and Echidna 1. The increase in mud weight
in Echidna 1 can be attributed to poor hole conditions and
hence does not represent an indication of increased pore
pressure per se. In contrast, the increase in mud weight in
Greenly 1 is associated with an increase in pore pressure, as
witnessed by the elevated RFT values.
In general, most of the region is normally pressured, with
only a small indication of overpressure below 3600 m
in Greenly 1. Hydrostatic pressures are assumed in the
analysis of fault reactivation risk, but in areas where
overpressures are anticipated, these predictions would need
to be modified.
20 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
RISKING FAULT REACTIVATION AND SEAL INTEGRITYFault reactivation is closely linked to sub-surface fluid flow
and hence to the processes of primary, secondary and
tertiary hydrocarbon migration, trap filling and trap spilling
(specifically trap breach). There is abundant evidence that
active faults and fractures, i.e., those subject to stresses
close to those that would induce failure, provide high
permeability conduits for fluid flow during deformation
(Sibson, 1994; Barton et al., 1995). Reactivation can
breach fault-bound traps even if there is fault juxtaposition-
and/or fault damage-related seal. Furthermore, active faults
and fractures provide conduits for fluid flow even in shaly
systems (Dewhurst et al., 1999).
Sibson’s (1992) fault-valve model is a useful one within
which to view the episodic transmission of fluids along
fault planes. Fault reactivation leads to the creation of
fracture permeability, and thus, fluid discharge/re-migration,
thereby decreasing pore pressure/hydrocarbon buoyancy
pressure. The fractures become sealing post-discharge due
to processes such as diagenetic precipitation, and fracture
permeability is destroyed, i.e., the faults and fractures do
not provide conduits for fluid flow when they are not subject
to stresses close to those that induce failure. The destruction
of fracture permeability allows pore pressures to increase
and/or hydrocarbon columns to accumulate once again.
Increasing pore pressure may then once again lead to fault
reactivation, the creation of fracture permeability, and fluid
discharge/re-migration, thus the process continues cyclically.
In the FAST (Fault Analysis Seal Technology) technique used
herein, the risk of fault reactivation is determined using the
stress tensor (Mohr circle) and fault-rock strength (failure
envelope). Brittle failure is predicted if Mohr’s circle touches
the failure envelope. All fault orientations plot within the
Mohr’s circle, and those closest to the failure envelope,
are at greatest risk of reactivation. The horizontal distance
between each fault plane and the failure envelope indicates
the increase in pore pressure (∆P) required to cause
reactivation and is used as the measure of the likelihood
of fault reactivation in the FAST technique. A small ∆P
Case SHmax
’ (MPa) Sv’ (MPa) S
hmin’ (MPa) Fault regime S
Hmax orientation
I 18.7 10.5 6.0 strike-slip 130oN
II 10.5 10.5 6.0 strike-slip/normal 130oN
III 8.5 10.5 6.0 normal 130oN
Note: The cases cover a range of possible values of SHmax
’ within the frictional limits. The magnitude values have been calculated for a depth of 1000 m below seabed.
Table 9.2 Parameters used in the three cases to model fault reactivation and seal integrity in the Bight Basin
21 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
200054-027
Dep
th b
elo
w m
ean
sea leve
l in
metr
es
Stress in MPa
20
1000
SHmax
Sv
Shmin
Seabed
Hydrostatic
40 60 7000
500
2000
1500
2500
Figure 9.13 An example plot of total stress versus depth for a water depth
Figure 9.13 An example plot of total stress versus depth
for a water depth of 400 m. The values for the total
stress and effective stress at 1400 m depth are listed in
Table 9.3.
22 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
infers a high likelihood of reactivation and a large ∆P infers
a low likelihood of reactivation. The ∆P value for each
plane can be plotted on a steronet as poles to planes. The
risk of reactivation of any pre-existing fault orientation is
then read from the steronet. A composite Griffith-Coulomb
failure envelope has been assumed in this study. No fault
rock failure envelopes are available for the area, and thus a
cohesive strength of 5 MPa and friction angle of 0.6 have
been assumed. For a more detailed discussion on the FAST
methodology, see Mildren et al. (2002).
A schematic FAST map with two simple, fictitious faults has
been created to demonstrate the risk associated by varying
the strike and dip (Fig. 9.15) of the faults. The stress field
applied to this example is the same as that in Case I (Table
9.2). Fault A has a constant strike of 120°N and a variable
dip from 90° in the northwest to 0° in the southeast. This
fault plots as a straight line on the steronet radiating out
from the centre at 30°, since they are plotted as poles to
planes. Fault B has a constant dip of 70° with a variable
strike ranging from north–south to east–west. This fault plots
as an arc on the steronet between 90° and 180°. Faults
with both varying strike and dip will plot as a combination
of styles illustrated by the two end-member cases above.
Given the often-complex history of changes in the stress
field that controls the structural evolution of sedimentary
basins, the in situ stress field, as constrained herein,
cannot be extrapolated back in time and applied to previous
structural events. Knowledge of the in situ stress field can
only elucidate contemporary tectonic activity.
FAULT REACTIVATION AND SEAL INTEGRITY IN THE BIGHT BASINIn Case I (strike-slip stress regime), vertical faults striking
between ~100°N and 160°N are the most likely to be
reactivated (Fig. 9.16b). Hence, traps requiring such faults
to be sealing are the most likely to be breached within the
in situ stress field. Vertical faults striking 130°N are located
between that conjugate shear pair and are also at high risk
of reactivation/breach. Faults striking between 75°N and
180°N show little reduction in their risk of reactivation with
decreasing dip until shallow dips (<40°) are attained. Faults
striking 40°N, and with any dip (and horizontal planes), are
Table 9.3 Total stress and effective stress values calculated for a depth of 1400 m below mean sea level and a water depth of 400 m (Fig. 9.13)
Depth Pore Total stress (MPa) Effective stress (MPa)
(m) pressure Shmin
Sv
SHmax
Shmin
’ Sv’ S
Hmax’
1400 m 14.1 20.1 24.6 32.8 6 10.5 18.7
23 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
200054-028
Stress in MPa
Dep
th in
metr
es
1000
Hydrostatic
Jerboa-1-RFT
Jerboa-1
Mercury-1
00
2000
3000
4000
5000
10 20 30 40 50 60 70
Greenly-1-RFT
Borda-1
Duntroon-1
Echidna-1
Greenly-1
Platypus-1
Vivonne-1
Potoroo-1
Columbia-1
Figure 9.14 Stress-depth plot showing mud weights
used in each well and RFTs in Jerboa 1 and Greenly 1.
Most of the Bight Basin appears normally pressured. Note
depth is from mean sea level.
24 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
A - Constant strike, variable dip
0
50
100
150
B - Constant dip, variable strike
1000 200
A - Constant strike, variable dip
B - Constant dip, variable strike
200054-030
P20
11
2
0
30
60
90
120
150
180
210
240
270
300
330
Figure 9.15 FAST map of two fictitious faults using the stress field in Case I. Fault A has a constant strike of 120° N and a variable dip from 90° in the
northwest to 0° in the southeast. Fault B has a constant dip of 70° with a variable strike ranging from north–south to east–west. Note the faults plot on
the steronet as poles to planes.
25 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
the least likely to be reactivated. Hence, traps requiring such
faults to be sealing are the least likely to be breached within
the in situ stress field. At 1 km depth, and assuming the
failure envelope in Figure 9.16a, vertical 160°N and 100°N
trending faults require an increase in pore pressure of only
slightly in excess of 2 MPa for reactivation/seal breach.
Both Case II (strike-slip/normal stress regime) and Case
III (normal stress regime) show significantly less range in
∆P values than in Case I (Fig. 9.16b, c). The ∆P values in
Cases II and III range between 5.8 and 10 MPa. In Case
II, faults striking 40°N of any dip are the least likely to be
reactivated. In Case III, however, horizontal faults with dips
up to 30° are the least likely to be reactivated. In general,
most fault orientations and dips in both Case II and III show
a similar propensity to be reactivated.
In all three cases, faults striking 40°N (±15°) of any dip
are the least likely to be reactivated. The magnitude of ∆P
required to reactivate faults of this orientation decreases
from Case I to Case III. Thus, traps requiring such faults to
be sealing are the least likely to be breached within all three
of the stress scenarios investigated.
IMPLICATIONS FOR EXPLORATION PROSPECTIVITY
The evaluation of the stress field and the attendant
potential for fault reactivation has important implications
for petroleum exploration within the Bight Basin. Although
an accurate assessment of the fault reactivation risk is
not possible based on the current level of incomplete
information and interpretation, some trends can be
established and discussed.
To facilitate the visualisation of the results of this study, the
results have been posted on a series of fault orientations for
the Sea Lion (Late Jurassic) rift faults and the Tiger (Late
Cretaceous: Turonian to Santonian) reactivated gravity faults
in the Eyre and Ceduna Sub-basins (Fig. 9.17). These fault
polygons are based on the interpretation of Totterdell et al.,
Chapter 4. The FAST results for Case I (strike-slip), Case
II (strike-slip-normal) and Case III (normal) for these faults
are summarised in map view on Figures 9.18, 9.19 and
9.20 respectively. The fault polygons have been assigned a
range of dips, specifically 25°, 40°, 55° and 70°, so that an
impression can be gained as to how these variously dipping
fault arrays would behave under a range of stress conditions.
To provide a more regional context, Early Cretaceous fault
trends in the Duntroon Sub-basin and eastern Ceduna Sub-
basin (from Totterdell et al., Ch. 4) have been plotted on
Figure 9.17 as well, although their reactivation risk was not
analysed.
As discussed in the previous section, in faults which dip at
25° (Figs 9.18a, 9.19a, 9.20a), it is clear that there is little
risk of reactivation, irrespective of the fault orientation and
the type of stress field present. However, as the dips increase
to 40°, it becomes apparent that the risk of fault seal failure
26 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
030
60
90
120
150180
210
240
270
300
330
030
60
90
120
150180
210
240
270
300
330
030
60
90
120
150180
210
240
270
300
330
0 10 20
Effective Normal Stress
0
0
0
4
4
4
8
8
8
12
12
12
Sh
ea
r S
tre
ss
Shear
Str
ess
Shear
Str
ess
(b) Case I
(c) Case II
(d) Case III
P
20
11
2
0Shmin/Sv
0
1
2
3
SH
max/S
v
Reverse
Strike-Slip
Normal
Case III
(a)
Case I
Case II1
2 3
0 10 20
Effective Normal Stress
P
20
11
2
P
20
11
20 10 20
Effective Normal Stress200054-029
Figure 9.16 Risk of fault reactivation. (a) Location in stress space of the three in situ
Figure 9.16 Risk of fault reactivation. (a) Location
in stress space of the three in situ stress cases
evaluated (Table 9.2). (b, c, d) Left hand side
is Mohr’s circle of stress and failure envelope
(assumed) used to calculate the likelihood of
reactivation for each case. Right hand side is
the likelihood of fault/fracture plane reactivation,
represented as poles to planes, for the three cases
(Table 9.2). Numerical values on scales refer
to increase in fluid pressure required to cause
reactivation (∆P). Equal angle, lower hemisphere
stereographic projection of poles to planes.
27 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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�� ���!"!#$%�
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��%&�'&���'�����'&���
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��&����(&����)�����(&����
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��&���������%��������%��
*�&�����&+�(�����,��&�������&��&��'����-���������&�*���.*&���/��&�������(�0�&�%�)�����.*&���1���&�����+��2��(�0�(&����+�����.&(����)����%�������&�-�
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Figure 9.17 Location map of the Great Australian Bight showing Sea Lion (Late Jurassic) and Tiger (Late Cretaceous) fault polygons (after Totterdell et al., Ch. 4) used in the fault reactivation
risks analysis. Also shown are Early Cretaceous fault trends in the Duntroon Sub-basin and eastern Ceduna Sub-basin (after Totterdell et al., Ch. 4).
28 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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Figure 9.18 Fault reactivation risks calculated using FAST technique for Case I (strike-slip stress regime) applied to fault polygons shown in Figure 9.17, assuming constant fault
dips of 25°, 40°, 55° and 70° respectively.
29 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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Figure 9.19 Fault reactivation risks calculated using FAST technique for Case II (strike-slip-normal stress regime) applied to fault polygons shown in Figure 9.17, assuming constant
fault dips of 25°, 40°, 55° and 70° respectively.
30 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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Figure 9.20 Fault reactivation risks calculated using FAST technique for Case III (normal stress regime) applied to fault polygons shown in Figure 9.17, assuming constant fault dips
of 25°, 40°, 55° and 70° respectively.
31 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
becomes greater in the northwest trending fault arrays
within the Ceduna Sub-basin. In contrast, the more east to
northeast trending faults in the Eyre Sub-basin are at low risk
of reactivation. At dips of 55°, the risk of fault seal failure
appears to be low within the Eyre Sub-basin, where the
faults have a generally northeast trend. However, in the more
north–west trending faults arrays, the risk of reactivation is
much higher, especially under a strike-slip stress regime. An
exception is the small, east–west trending, intra-basinal Sea
Lion faults which occur within the overall, northwest trending
Sea Lion faults in the Ceduna Sub-basin. These faults have a
low risk of reactivation compared to the northwest trending
faults that dominate this part of the Bight Basin. At fault dips
of 70°, there is a high risk of reactivation of the northwest
trending fault sets of the Ceduna Sub-basin, for all stress
regimes. The exception is again the small, more east–west
trending fault arrays. The Eyre Sub-basin appears to have a
low risk of reactivation, particularly in the strike-slip-normal
and strike-slip stress regimes.
Overall, the results suggest that under the strike-slip-normal
or normal stress regime, there appears to be little risk of
reactivation in fault systems which trend east–west or
northeast, almost irrespective of fault dip. Clearly, the rift
faults of the Eyre Sub-basin and the intra-basinal, east–west
trending faults of the Ceduna Sub-basin all have a low risk
of fault reactivation. In contrast, the results suggest that
the rift and post-rift faults of the Ceduna, and by inference
the Duntroon, Sub-basins have a relatively high risk of
reactivation once dips exceed approximately 40°, for a strike-
slip-normal or normal stress regime. Traps with the lowest
risk in the Ceduna and Duntroon Sub-basins, with respect
to reactivation, are those with lower (<~40°) dips on the
bounding faults or those with a more east–west orientation.
A key question is: how do these models agree with the
empirical observations from the region?
Firstly, if earthquake data is considered, it appears that the
most common earthquakes occur in the eastern Ceduna
Sub-basin and in the Duntroon Sub-basin (Fig. 9.21),
broadly through the area with northwest trending fault
arrays. However, the rest of the Bight appears to be largely
aseismic, and this may suggest that the stress regime in the
central and western Bight is less conducive to reactivation.
Another factor is the distribution of oil slicks which have
been mapped in the region (Struckmeyer et al., 2002;
O’Brien et al., Ch. 10) via the use of satellite-based
Synthetic Aperture Radar (SAR). These slicks are generally
more common within the deep water Ceduna Sub-basin
and eastern parts of the Great Australian Bight (along
the northwest fault arrays), but the frequency of the SAR
slicks is so low, and their distribution so scattered, that
the results neither support nor refute the stress results.
However, although there is a relative risk of northwest
trending fault arrays reactivating in the Ceduna Sub-basin
under the present stress regime, there are few faults in the
Ceduna Sub-basin that actually reach the sea floor. Most
32 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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Figure 9.21 Regional map showing Sea Lion and Tiger fault polygons (after Totterdell et al., Ch. 4) along regional tectonic elements, plotted with wells, earthquake epicentres and
SAR slicks.
33 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
sea floor faults in the Ceduna Sub-basin are concentrated
on the continental slope where the Cainozoic cover is thin
to absent, and appear to have originated from gravity-driven
processes in the Late Cretaceous rather than regional stress
effects. Seismic gas chimneys are very common within the
eastern Ceduna and Duntroon Sub-basins (O’Brien et al.,
Ch. 10) and correlate spatially with water column sniffer
anomalies. These chimneys typically relate to the northwest
trending fault arrays in the region, so this may support some
loss of fault seal integrity in this area.
Finally, it is interesting to note that the only confirmed
palaeo-oil column in the region was located in Jerboa 1, in
the Eyre Sub-basin. This area is predicted, under the present
day stress regime, to be of high fault seal integrity. Ruble et
al. (2001) proposed, however, that this trap was actually
breached in the Late Cretaceous. This emphasises the fact
the stress predictions only relate to the present day, and not
to palaeo-reactivation events, when the stresses may have
been quite different. It also emphasises the fact that the
timing of hydrocarbon migration (and probably the nature of
the hydrocarbon charge) is very important in relation to trap
reactivation. Relatively low to moderate fault seal integrity
may be beneficial in regions which are now experiencing a
high gas charge, for example, as this may help to reduce
the risk of gas flushing in traps in such areas which were
previously charged with oil (O’Brien and Woods, 1995).
These observations highlight the fact that the results
presented in this chapter should not be used in isolation. It
does appear clear that relatively steeply dipping faults with
a generally northwest trend will be prone to reactivation,
whereas more east–west or northeast trending faults will
have little tendency to reactivate, irrespective of dip. Such
observations should be integrated with other aspects of the
petroleum system, such as the generation history, remote
sensing results, and Direct Hydrocarbon Indicator mapping,
to better determine how critical the present day stress
environment is to hydrocarbon prospectivity in the Bight
Basin.
For individual traps, the assessment of fault breaching risk
requires detailed prospect studies, so that FAST analysis can
be applied to clearly defined, depth-converted fault planes
interpreted from seismic data. Also, in situ stress field
characteristics should be based on local well measurements
and the failure envelope constrained by properties specific to
the analysed rocks.
34 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
REFERENCES
Barton, C.A., Zoback, M.D. and Moos, D., 1995. Fluid flow along
potentially active faults in crystalline rock. Geology, 23(8):683-
686.
Bell, J.S., 1990. The stress regime of the Scotian Shelf offshore
eastern Canada to 6 kilometres depth and implications for
rock mechanics and hydrocarbon migration. In: Maury, V. and
Fourmaintraux, D. (Eds), Rock at great depth. Rotterdam,
Balkema, pp. 1243-1265.
Breckels, I.M. and van Eekelen, H.A.M.,1982. Relationship
between horizontal stress and depth in sedimentary basins.
Journal of Petroleum Technology, 34:191-2198.
Dewhurst, D.N., Yang,Y. and Aplin, A.C.,1999. Permeability and
fluid flow in natural mudstones. In: Aplin, A.C., Fleet, A.J. and
Macquaker, J.H.S. (Eds), Mud and mudstones: physical and fluid
flow properties. Geological Society, London, pp. 23-43.
Dickson, G. 1953. Geological aspects of abnormal reservoir
pressures in Gulf Coast Louisiana. AAPG Bulletin, 37:410-432.
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35 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Austral ian Bight
1Introduction
2History of
petroleum
exploration
3Natural environment
and environmental
management
4Structural
and tectonic
setting
5Biostratigraphy
6Stratigraphy and
environments of
deposition
7Source rock
geochemistry
and strandings
8Thermal
maturation
history
9Stress analysis,
fault reactivation
and seal integrity
10Direct
hydrocarbon
indicators
11Reservoirs and
seals of the
Bight Basin
12Play types
13Integration:
prospectivity
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