REGIONAL GEOLOGY OF THE PERTH BASIN
BASIN OUTLINE
The Perth Basin is a large (172,300 km2), elongate, north to northwesttrending sedimentary basin extending about 1,300 km along the southwestern
coast of Australia and encompassing both the onshore and offshore
(Figure 1). The Perth Basin was originally named by Andrews (1938), and
has been described and mapped by Playford et al (1976) and Hocking (1994).
The maximum extent of the offshore part of the Perth Basin is placed at the
limit of basin fill ranging in age from Cisuralian (early Permian)–Early
Cretaceous (Bradshaw et al, 2003).
Crystalline basement beneath the Perth Basin comprises Proterozoic igneous
and metamorphic rocks of the Pinjarra Orogen which formed as an
intercontinental mobile belt between the Australian and Indian parts of eastern
Gondwana (Collins, 2003). The Darling Fault system forms the eastern
boundary of the Perth Basin (Figure 1 and Figure 2), controlling its overall
north-south orientation. It originated as a shear zone during the Archean
(Blight et al, 1981; Dentith et al, 1994) and was reactivated to form a major
rift-border fault to the incipient Perth Basin during the Cisuralian (Crostella
and Backhouse, 2000). The Perth Basin is isolated from the Mentelle Basin in
the southwest by the Leeuwin Complex and Yallingup Shelf (Figure 1), and
from the Wallaby Plateau to the northwest by thick and extensive volcanic
deposits that erupted during the Early Cretaceous break-up of Australia and
Greater India (Colwell et al, 1994; Symonds et al, 1998; Sayers et al, 2002).
The offshore part of the basin is composed of four sub-basins (Figure 1). The
Abrolhos and Houtman sub-basins in the north contain a thick succession (813 km) of Permian to Jurassic sediments (Figure 2; Bradshaw et al, 2003).
The Zeewyck Sub-basin in the northwest and Vlaming Sub-basin in the south
are predominantly Mesozoic depocentres comprising 7-14 km of Middle
Jurassic to Lower Cretaceous strata. The boundaries between the sub-basins
have been interpreted to have formed through oblique-slip motion in a
transtensional setting (Marshall et al, 1989a). In the northern Perth Basin, the
offshore and onshore depocentres are separated by an intra-basin high
comprising the Beagle Ridge and Dongara Terrace (Figure 1 and Link to the
Perth Basin REGIONALFigure 2). Descriptions of the onshore structural
elements are given by Hocking (1994), Iasky (1993), Mory and Iasky (1996),
and Crostella and Backhouse (2000).
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Northwest–southeast trending accommodation zones have been advocated
as controlling the structural compartmentalisation of rift systems in the Perth
Basin. For example, the Abrolhos and Cervantes transfers are interpreted to
divide the northern Perth Basin into regions of significantly different structural
character (Figure 1; Mory and Iasky, 1996).
Both oil and gas are produced from a number of fields in the onshore Perth
Basin and, since 2006, from the offshore Cliff Head oil field (Figure 3). The
Cliff Head oil field is the first commercial oil discovery in the offshore Perth
Basin and produced 1.42 mmbl (225,581 kL) of oil in 2009 (DMP, 2010).
There is an established gas pipeline network in Western Australia servicing
the Perth Basin (Figure 3).
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BASIN EVOLUTION AND TECTONIC DEVELOPMENT
The Perth Basin formed through pre-breakup continental extension between
the southwestern continental margin of Australia and Greater India. The latter
includes the Indian sub-continent and a postulated northern extension of it
(Matte et al, 1997; Ali and Aitchison, 2005). The tectonic and
palaeogeographic history of the Perth Basin has been documented in several
previous studies (Smith and Cowley, 1987; Marshall et al, 1989b, 1993;
Harris, 1994; Quaife et al, 1994; Mory and Iasky, 1996; Song and Cawood,
2000; Crostella and Backhouse, 2000; Gorter and Deighton, 2002; Bradshaw
et al, 2003; Norvick, 2004). These authors generally describe an early phase
of rifting, followed by a long period of widespread post-rift subsidence, with a
final extensional phase culminating in breakup, although the timing of key
events varies between studies.
Early to late Permian rifting
Early Permian rifting resulted in the formation of a series of half-graben in the
Perth Basin that are separated by saddles and characterised by en-echelon
border fault relationships (Figure 2 and Figure 4 Figure 5a; Norvick, 2004).
This graben complex ran at least from the Southern Carnarvon Basin in the
north to the Bunbury Trough in the south. In many cases, but not exclusively,
the original rift phase was aligned north-south (Quaife et al, 1994). Active
faulting slowed in the north from the Sakmarian onwards (Norvick, 2004).
Initially, the basins were filled with glacial (Nangetty and Mosswood
formations) to pro-glacial marine (Holmwood Shale and High Cliff and
Woodynook sandstones) and deltaic sediments (Irwin River and Rosabrook
coal measures; Mory and Iasky, 1996; Norvick, 2004). Deglaciation
commenced in the Sakmarian and the rifts continued to fill from the south to
north with deltaic (Ashbrooke Sandstone, Redgate Coal Measures and
Willespie Formation) to progressively more marine sediments (Carynignia
Formation; Norvick, 2004).
Late Permian uplift and erosion
In the northern Perth Basin, the end of the early Permian is marked by a
regional low-angle, tectonically enhanced unconformity associated with
uplifted, tilted fault blocks being exposed to subaerial erosion (Roc, 2004).
This uplift was “interrupted by late Permian to early Triassic rifting and the
deposition of a series of coalesced, coarse-grained alluvial deltas” (Mory and
Iasky, 1996, p. 59; Wagina Formation). A second phase of proximal fan to
coarse-grained deltaic deposition (Dongara Sandstone; Mory and Iasky,
1996) occurred during or subsequent to another ‘tectonic re-organisation’
(Laker, 2000, p. 3), which may have been associated with strike-slip
movement (Laker, 2000).
Triassic to Middle Jurassic post-rift subsidence
There was a subtle basin reorganisation at the beginning of the Triassic in
which deposition spread out over a much larger area than in the late Permian
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(Figure 2 and Figure 5b; Norvick, 2004), resulting in an extensive and rapid
marine transgression throughout the Perth Basin (Kockatea Shale) and basins
to the north (Carnarvon, Canning and Bonaparte basins). Sandier facies in the
south of the Perth Basin (Sabina Sandstone) suggest that the basin was
closed and filling from this direction (Norvick, 2004). Subsequent to the
regional marine transgression maximum in the Early Triassic there was a
regression to deltaic and fluvial facies throughout the Middle to Late Triassic
(Woodada Formation and Lesueur Sandstone; Figure 4 and Figure 5c; Mory
and Iasky, 1996). Palaeocurrent data show these Triassic rivers flowed from
the south or southwest (Mory and Iasky, 1996) and they are assumed to have
covered both the Perth Basin and much of the Yilgarn Craton (Norvick, 2004).
In at least some parts of the Perth Basin, the prolonged phase of post-rift
subsidence appears to have been interrupted by a minor phase of westnorthwest – east-southeast oriented rifting during latest Triassic to Early
Jurassic (Figure 4; Song and Cawood, 1999, 2000; Bradshaw et al, 2003).
This extension reactivated a number of faults in the basin, with syn-tectonic
deposition of non-marine red beds (Eneabba Formation). This mild tectonism
was followed by deposition of delta-top swamp deposits (Cattamarra Coal
Measures), perhaps during a regional transgression (Figure 5d; Norvick,
2004). This transgression peaked in an extensive but short-lived marine
flooding event in the Bajocian (Cadda Formation; Figure 5e).
Middle Jurassic to Early Cretaceous rifting and breakup
An abrupt resumption of fluvial sedimentation in the Bajocian (Yarragadee
Formation) was accompanied by the onset of major extensional faulting
(Figure 4 and Figure 5f). In the Tithonian to Berriasian, there was a poorly
delineated change to red bed sedimentation (Parmelia Group), which also
probably occurred in a syn-rift setting (Norvick, 2004). The deeper water parts
of the basin may have received deltaic or marine equivalents of these
sediments at that time.
The northwest-southeast extension from the Middle Jurassic to earliest
Cretaceous culminated in the break-up of Australia and Greater India during
the Valanginian, and produced much of the final structural architecture of the
Perth Basin (Figure 1; Bradshaw et al, 2003). Early Cretaceous break-up was
associated with widespread uplift and erosion (Figure 2), and possibly also
with deep-seated strike-slip faulting and vulcanism.
A phase of basin subsidence followed in the Early Cretaceous (Valanginian–
Aptian; Quaife et al, 1994), which may have been associated with widespread
volcanic activity in the Perth Basin (Gorter and Deighton, 2002), and on the
Wallaby Plateau (Symonds et al, 1998). Submarine sediments, including
turbidites in the more basinal areas (Warnbro Group), were deposited through
localised sagging (Norvick, 2004).
Late Cretaceous and Cenozoic sedimentation occurred under stable, passive
margin conditions and produced a thin cover of predominantly marine
carbonates. During the Neogene to Quaternary there was a vertical transition
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from cool-water ramp sedimentation to reefal platform development (Houtman
Abrolhos coral reefs) near the shelf edge in some places (Collins et al, 1998).
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REGIONAL HYDROCARBON POTENTIAL
Hydrocarbon Families and Source Rocks
Geochemical studies on petroleum from the Perth Basin, using modern
analytical techniques (i.e. biomarkers by GCMS, carbon and hydrogen
isotopes by compound specific isotopic analysis - CSIA) have given detailed
insights into the origin of the gaseous and liquid hydrocarbons (Summons et
al, 1995; Boreham et al, 2001; Gorter et al, 2004; Thomas and Barber, 2004,
Dawson et al, 2005a; Geoscience Australia and Geomark, 2005; Geotech,
2005; Grice et al, 2005; Volk et al, 2009; Kempton et al, in press), although
many questions still remain unresolved. Based on these studies and ongoing
analyses of hydrocarbons recovered from more recent discoveries, as well as
some legacy samples, several hydrocarbon families and associated
petroleum systems are recognised in the Perth Basin: Permian, Triassic,
mixed Permian-Triassic, Jurassic and Upper Jurassic/Lower Cretaceous
(Figure 6, Figure 7 and Figure 8). The majority of oils and condensates from
the northern Perth Basin are sourced entirely from the sapropelic interval of
the Hovea Member of the Triassic Kockatea Shale (Table 1). However, there
are locally important hydrocarbons in the Perth Basin that are sourced solely
from older and younger successions, or which contribute to the Lower Triassic
marine petroleum system (Table 2).
1 Permian sourced hydrocarbons (Sue Group and Irwin River Coal Measures)
A number of gas/condensate discoveries in the onshore Perth Basin were
sourced entirely or in part from Permian coal measures. The Whicher
Range 1 (Figure 8) condensate (and by inference, the associated gas) from
the Bunbury Trough in the southern Perth Basin is believed to have been
sourced locally from coal measures in the Permian Sue Group (Summons et
al, 1995). It has an isotopic signature enriched in 13C (13C ~ -25‰, Figure 6;
Summons et al, 1995) and a dominant land-plant biomarker assemblage (e.g.
high pristane/phytane and C29/C27 sterane ratios) that are distinctive of
Permian-sourced hydrocarbons.
Similar isotopically heavy gas was recovered from the Irwin River Coal
Measures in Elegans 1 on the Beharra Springs Terrace (Figure 8), east of the
Dongara Terrace (Figure 6; Boreham et al, 2001). Thomas and Barber (2004)
suggested a mixed Permian-Lower Triassic source for the Elegans 1 gas, but
given the weak maturity control on the carbon isotopic composition of the
Perth gases (Figure 6), a sole Permian source is favoured here (Table 2).
Other samples that are believed to have been in part sourced from Permian
coal measures include gas from the Dongara field, oil from Woodada 3 and
fluid inclusion oil from Leander Reef 1 (Table 2); these are discussed
separately below.
2 Triassic sourced hydrocarbons (Hovea Member, Kockatea Shale)
From the beginning of petroleum exploration in the Perth Basin, the Lower
Triassic Kockatea Shale was recognised as the principal source for the oils
from the Dongara Terrace and immediate surrounds (e.g. Dongara, Mondarra,
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Mount Horner, North Erregulla and Woodada fields) in the onshore northern
Perth Basin (Table 1; Figure 8; Powell and McKirdy, 1973, 1976). More
recent discoveries of Kockatea Shale–sourced oils have extended beyond the
Dongara Terrace to the accumulations at Eremia, Hovea and Jingemia, and
offshore at Cliff Head (Thomas and Barber, 2004). Significantly, oil and fluid
inclusion oil from Hadda 1 (Table 1) and oil shows from Livet 1 and
Morangie 1 (Thomas and Barber, 2004) have shown that a Kockatea source
is effective in the northern part of the offshore Perth Basin (Figure 8).
Thomas and Barber (2004) constrained the effective source rock to an earliest
Triassic, middle sapropelic interval in the Hovea Member of the lower
Kockatea Shale. This source zone is typically 10–40 m thick and is
continuous over much of the onshore northern Perth Basin. Until recently,
Hovea Member source rocks have only been recognised offshore in Leander
Reef 1 (Thomas and Barber, 2004), but based on extensive new sampling
and analysis, the Hovea Member is now recognised in 17 wells on the
offshore Beagle Ridge and in the Abrolhos Sub-basin, and shows good to
excellent source rock potential for generating oil (Grosjean et al, 2010).
The Lower Triassic marine-sourced oils are typically waxy, with the most 13Cdepleted carbon isotopic signature of any Australian Phanerozoic oil (13C ~ 34 ‰; Powell and McKirdy, 1976). This extremely light signature is also
reflected in individual n-alkanes (13C < -32 ‰, Figure 6; Summons et al,
1995; Boreham et al, 2001; Gorter et al, 2004). Characteristic geochemical
signatures of the oils include pristane/phytane ratio <3, C29 steranes slightly
dominant over C27 steranes and abundant extended C28 + tricyclic
hydrocarbons (Geoscience Australia and GeoMark, 2005). An anomalously
high abundance of C33 n-alkylcyclohexane (Jefferies, 1984), phytanyltoluenes
and long-chained alkylnaphthalenes (Thomas and Barber, 2004) is unique
among Australian oils. However, these unusual biomarker signatures have a
strong maturity control and are generally absent in high maturity condensates.
Most onshore Perth Basin gases were originally believed to be sourced from
lower Permian coals (Owad-Jones and Ellis 2000), however, this is
inconsistent with their depletion in 13C (Figure 6) and a Kockatea Shale
source is more appropriate (Boreham et al, 2001).
3 Mixed Permian-Triassic sourced hydrocarbons
Oil recovered from Woodada 3 contains the C33 alkylcyclohexane biomarker
characteristic of the Hovea Member, but is isotopically heavier than the other
Lower Triassic-sourced oils (Figure 6), which led Summons et al (1995) to
suspect a variant Lower Triassic organic facies. However, a mixed oil is more
likely with input from either a Permian (Thomas and Barber, 2004) or a
Jurassic (Gorter et al, 2004) source.
Isotopic evidence for an admixture of Triassic and Permian-sourced liquids is
also found in one of the two oils analysed from Yardarino 1 (Figure 8). Whilst
one sample is essentially identical to oils sourced from the earliest Triassic
sapropelic interval (eg, Dongara 14; Figure 6) the other (that originally
analysed by Summons et al, 1995) has a marked trend to heavier isotopic
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values at the low carbon end (C9–C12) of the CSIA profile (Figure 6), which
suggests an addition of Permian condensate. Support for active generation
and charge from the Permian at this location comes from Elegans 1, a later
deepening of the Yardarino 1 well, as discussed above.
Another example of a dual source charge is the Dongara gas field (Figure 8).
The gas is relatively dry and the isotopic difference between methane and
ethane is much smaller than for other Perth gases from a single source
(Figure 6). At Dongara, the Permian charge is mainly isotopically heavy
methane, which has added to a wet gas from the isotopically light sapropelic
interval (Figure 6). The hydrogen isotopes are more diagnostic of this dual
source, with methane now isotopically heavier than ethane (Figure 7) due to
input of Deuterium-enriched methane from the Permian.
The Leander Reef 1 fluid inclusion oil is also considered a mixture of Lower
Triassic and Permian sources (Volk et al, 2004; Figure 8).
4 Jurassic sourced hydrocarbons (Cattamarra Coal Measures)
Hydrocarbons recovered from the Lower Jurassic Cattamarra Coal Measures
in the southern Dandaragan Trough (condensate at Walyering 1, 2) and
Beermullah Trough (oil at Gingin 1, 2 and Bootine 1; gas at Gingin West 1)
are locally sourced from the Lower Jurassic Cattamarra Coal Measures, as
originally suggested by Thomas (1984) and Summons et al (1995) (Figure 8).
The Walyering 1 and 2 condensates were previously interpreted to be derived
from marine-influenced source inputs from either the Triassic (Summons et al,
1995) or the Lower Jurassic Cattamarra Coal Measures (Gorter et al, 2004),
consistent with their intermediate carbon isotopic composition (Figure 6),
lower pristane/phytane ratio and the presence of the diagnostic marine C30
desmethylsterane (Summons et al, 1995). The Bootine 1 and Gingin 1
condensates are enriched in 13C and together with their saturated
hydrocarbon biomarkers are consistent with a Permian terrestrial source
(Geoscience Australia and GeoMark, 2005). However, higher-plant aromatic
biomarkers confirm the Jurassic affinity for the organic matter (Gorter et al,
2004). The Gingin West 1 gas reservoired in the Cattamarra Coal Measures is
also enriched in 13C (Figure 6) and is considered to have been sourced from
the Cattamarra Coal Measures.
A marine interval within the Lower Jurassic Cattamarra Coal Measures is
interpreted to be the source of oil reservoired in the Lower Jurassic Eneabba
Formation in Cataby 1 in the Beermullah Trough (Gorter et al, 2004;
Figure 8).
Inclusion oil recovered from the top of the Cattamarra Coal Measures in
Houtman 1, located in the offshore Houtman Sub-basin, could represent an
offshore extension of a similar Lower Jurassic source facies (Volk et al, 2004;
Figure 8).
5 Upper Jurassic-Lower Cretaceous sourced hydrocarbons (Yarragadee Formation)
Oil recovered from Gage Roads 1, in the Vlaming Sub-basin, is waxy,
isotopically heavy (13Coil ~ -24 ‰), displays a flat n-alkane 13C isotopic profile
(Figure 6), and has a relatively high content of conifer-derived aromatic
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hydrocarbons (Summons et al, 1995). As well as being isotopically the most
enriched in 13C of all the Perth Basin oils, it also has the lightest hydrogen
isotopes (D) of any Perth Basin oil (Figure 7; Dawson et al, 2005a, b);
hydrogen isotopes of n-alkanes cannot be used to readily distinguish
Kockatea Shale sources from either Jurassic (other than Gage Roads 1) or
Permian sources (Figure 7). The Gage Roads 1 oil is most likely derived from
a source rock within either the Upper Jurassic Yarragadee Formation or
Lower Cretaceous Parmelia Formation (Summons et al, 1995; AGSO and
GeoMark, 1996; Figure 8). However, the lacustrine source influence was
downplayed by Volk et al (2004), who favoured a source within the Parmelia
Formation.
The Warro 3 gas reservoired in the Yarragadee Formation is the most 13Cenriched gas from the Perth Basin. As such, it has some affinity with the Gage
Roads 1 oil (Figure 6). However, its hydrogen isotopic composition is
enriched in Deuterium compared to the Gage Roads 1 oil (Figure 7),
suggesting a different onshore source facies for this gas.
Charge history
Burial history modelling by Thomas and Barber (2004) suggested that the
timing of oil generation from the Kockatea Shale-Hovea Member-sapropelic
interval is virtually coincident with gas generation from the underlying Irwin
River Coal Measures. The modelling indicates that in most areas the oil
charge from the Lower Triassic is in direct competition with any gas being
generated from the Permian.
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EXPLORATION HISTORY
Petroleum exploration in the Perth Basin commenced in the late 1940s with
an onshore field survey and evaluation of water well drilling commissioned by
Ampol and Richfield Oil companies and gravity surveys by the Bureau of
Mineral Resources (BMR) (Mory & Iasky, 1996). Oil shows recorded in BMR
wells drilled on the Beagle Ridge in 1959-60 led West Australian Petroleum
Pty Ltd (WAPET) to drill the first wildcat hole, Eneabba 1, in 1961. The first
discovery in the Perth Basin was Yardarino gas field in 1964, with mixed
Permian and Triassic sourced hydrocarbons reservoired in the Wagina
Formation (Crostella, 1995). The Dongara oil and gas field, with oil and gas
sourced from the Lower Triassic Kockatea Shale and additional gas sourced
from lower Permian shales and coals, was discovered in 1966 and
commenced production in 1971 (Crostella, 1995). The discovery of gas and
oil in Gingin 1 and 2, drilled between 1964 and 1966, although uneconomic,
was significant in that it proved the effectiveness of sources from the Jurassic
succession (Crostella, 1995). Hydrocarbon discoveries in the onshore Perth
Basin have continued to the present, with a recent example being the Gingin
West 1 gas and condensate discovery in April 2010 (DMP, 2010).
Offshore exploration commenced in 1965, with the acquisition of the Abrolhos
and Perth Marine Seismic Surveys in the northern Abrolhos and southern
Vlaming sub-basins, respectively. Seismic data have been acquired
consistently since that time, giving a coverage that is a mixture of older
regional reconnaissance grids and more detailed surveys and scientific
studies. Seismic coverage is most concentrated in the Abrolhos Sub-basin
and the Wittecarra Terrace, and the central Vlaming Sub-basin. The southern
Houtman and southern Vlaming sub-basins are also covered by relatively tight
(<1-5 km line spacing) industry grids. Four 3D seismic surveys were acquired
in 2003 and 2004, and one later in 2008, all in the northern Perth Basin. The
most recent seismic acquisition in the basin was a series of regional 2D lines
over the frontier northern Houtman and Zeewyck sub-basins, part of
Geoscience Australia’s s310 seismic survey in 2008-09. In 2008-10,
Geoscience Australia commissioned the reprocessing of approximately
11,665 line km (180 lines) of seismic data from 17 surveys with vintages
spanning 1976-2003.
To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-andpromotion/2011.html#data-packages
The first well drilled in the offshore Perth Basin was Gun Island 1, a
stratigraphic well drilled by BP Petroleum Development Aust Pty Ltd in 1968.
This was followed by the first hydrocarbon discovery in the offshore Perth
Basin at Gage Roads 1 by WAPET in 1969. A total of 98.5 barrels of oil were
recovered from the Stragglers Member of the Carnac Formation at Gage
Roads, which remains the only accumulation found in the Vlaming Sub-basin.
A series of wells were then drilled in a campaign by WAPET from 1971-1978,
including Roe 1, Warnbro 1, Charlotte 1, Sugarloaf 1, Bouvard 1, and
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Challenger 1 in the Vlaming Sub-basin, South Turtle Dove 1B on the Turtle
Dove Ridge and Geelvink 1A in the Abrolhos Sub-basin.
A general lack of success in the WAPET drilling campaign subsequent to the
Gage Roads discovery led to a period of decreased exploration activity in the
basin, with only 10 wells drilled in the 1980s and 1990s, by companies such
as Esso Exploration and Production Australia Ltd and Ampol Exploration
Limited. In the offshore northern Perth Basin there was an 11 year hiatus
between the drilling of Wittecarra 1 in 1985 and Livet 1 in 1996.
The most recent phase of offshore exploration was underpinned by significant
uptake of permits covering much of the offshore northern Perth Basin in 200203. This widespread permit position in the offshore decreased from 2004-05,
with new petroleum exploration acreage released in the offshore northern
Perth Basin in 2003, 2004 and 2006 not taken up by industry. In contrast, new
permits were awarded in the southern Perth Basin (Vlaming Sub-basin) in
2005-06 and 2006-07 (Nicholson et al, 2008).
Recent drilling was undertaken primarily by ROC Oil (WA) Pty Ltd, who drilled
11 new field wildcat wells in the northern Perth Basin between 2001 and
2008. The Cliff Head oil field was discovered in 2001 with the first of these
exploration wells. The Cliff Head discovery, and a series of onshore oil
discoveries in the early 2000’s (Hovea, Jingemia, Eremia), changed the
perception of the northern Perth Basin from being marginally prospective for
gas to one that is highly prospective for gas and oil (Buswell et al, 2004).
Cliff Head 1 intersected a 4.8 m waxy (31.6° API) oil column in the Irwin River
Coal Measures immediately beneath the Kockatea Shale regional seal (Jones
and Hall, 2002). Seismic interpretation of the Cliff Head oil field has shown it
to be structurally complex with reverse faults, wrench faults and listric faults
mapped at both field and reservoir scale within the Permo-Triassic section
(Hodge, 2005). Five extension/appraisal wells were drilled between 2002 and
2005 to delineate the extent of the Cliff Head field, and seven
development/water injection wells were drilled between 2005 and 2006.
Production from the Cliff Head field commenced in 2006 with a total of 9 mmbl
(1.43 x 106 kL) of oil produced as at 31 December 2009 (DMP, 2010).
Three other discoveries were made in 2007 as part of ROC Oil’s drilling
campaign, with Frankland 1, Dunsborough 1 and Perseverance 1 all
intersecting gas columns, and Dunsborough 1 included a light oil leg.
Presently, there are three offshore exploration permits active in the Perth
Basin, and all are in the Vlaming Sub-basin: WA-368-P, operated by Nexus
Energy Australia Ltd; and WA-381-P & WA-382-P, operated by Westralian
Petroleum Ltd. ARC (Offshore PB) Ltd, AWE Oil (Western Australia) Pty Ltd,
Cieco Energy Australia Pty Ltd and ROC Oil (WA) Pty Ltd are the registered
holders of Production License WA-31-L over the Cliff Head oil field in the
northern Perth Basin.
Exploration continues to be active in the onshore parts of the Perth Basin for
conventional oil and gas plays, as well as a recent upsurge in unconventional
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gas exploration (tight gas, shale gas and underground coal gasification). The
primary targets for unconvential gas are the Kockatea Shale, Carynginia
Formation and Irwin River Coal Measures.
.
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FIGURES
Figure 1:
Structural elements map for the Perth Basin (modified from
Bradshaw et al, 2003). Also shown is the location of the cross
section illustrated in Figure 2.
Figure 2:
Regional transect through the Perth Basin (modified from
Norvick, 2004).
Figure 3:
Oil and gas fields and selected hydrocarbon discoveries and
occurrences in the Perth Basin and the associated
infrastructure.
Figure 4:
Stratigraphy of key elements and regions in the Perth Basin,
including hydrocarbon shows and accumulations, tied to the
Geologic Time Scale after Gradstein et al (2004) and Ogg et al
(2008). Sea level curve after Hardenbol et al (1998), Haq and
Al-Qahtani (2005) and Haq and Schutter (2008).
Figure 5:
Palaeogeographic sketch maps of the Perth Region: a)
Cisuralian – Artinksian; b) Early Triassic – Induan; c) Late
Triassic – Carnian; d) Early Jurassic – Toarcian; e) Middle
Jurassic – Bajocian; f) Late Jurassic – Oxfordian; g) Early
Cretaceous – Hauterivian; h) Early Cretaceous – Aptian
(modified from Norvick, 2004).
Figure 6:
Carbon isotopic composition of C1–C5 gaseous hydrocarbons
and C7–C28 n-alkanes of oils from the Perth Basin. Colours
correspond to interpreted age of generative source rock.
Figure 7:
Hydrogen isotopic composition of C1–C5 gaseous hydrocarbons
and C7–C28 n-alkanes of oils from the Perth Basin. Colours
correspond to interpreted age of generative source rock.
Figure 8:
Oil and gas fields and selected hydrocarbon discoveries and
occurrences annotated by age of source rock as interpreted
from geochemical evidence.
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TABLES
Table 1:
Perth Basin gases and oils sourced from the Early Triassic
Kockatea Shale.
Table 2:
Perth Basin gases and oils of mixed origin or from Jurassic and
Permian sources.
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REFERENCES
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Front page image courtesy of Petroleum Geo-Services.
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