35
1 Introduction 2 History of petroleum exploration 3 Natural environment and environmental management 4 Structural and tectonic setting 5 Biostratigraphy 6 Stratigraphy and environments of deposition 7 Source rock geochemistry and strandings 8 Thermal maturation history 9 Stress analysis, fault reactivation and seal integrity 10 Direct hydrocarbon indicators 11 Reservoirs and seals of the Bight Basin 12 Play types 13 Integration: prospectivity 9 Stress analysis, fault reactivation and fault seal integrity in the Bight Basin SD Reynolds 1 , RR Hillis 1 and GW O’Brien 1 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: Great Australian 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 S Hmax 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 . . . . . . . . . . . . . . . . 32 1 Australian School of Petroleum, University of Adelaide, Adelaide SA 5005 email: [email protected], mailto:[email protected], mailto:[email protected]

1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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Page 1: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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]

Page 2: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 3: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 4: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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.

Page 5: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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).

Page 6: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 7: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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.)

Page 8: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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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Figure 9.4(b) Earthquake data in the Great Australian Bight region — Earthquake magnitudes. (Data provided by D Love, PIRSA.)

Page 9: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 10: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

-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).

Page 11: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 12: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 13: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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.

Page 14: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 15: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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.

Page 16: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 17: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

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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.

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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.

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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

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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.

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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

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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.

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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.

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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

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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.

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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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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).

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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.

Page 29: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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.

Page 30: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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.

Page 31: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

Page 32: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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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Page 33: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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.

Page 34: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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

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Page 35: 1 • PETROLEUM GEOLOGY OF SOUTH AUSTRALIA Volume 5: …petroleum.statedevelopment.sa.gov.au/__data/assets/pdf... · 2015-09-10 · Introduction 2 History of petroleum exploration

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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