PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREAS W12-10, W12-11, W12-12,
W12-13 AND W12-14
EXMOUTH PLATEAU, NORTHERN
CARNARVON BASIN, WESTERN AUSTRALIA
HIGHLIGHTS

Australia’s premier deep-water gas province

Deep to ultra deep water depths 850–4,500 m

Adjacent to multi-Tcf gas fields and numerous recent discoveries

Close to existing and planned regional LNG facilities

Fault block and structural/stratigraphic traps
Release Areas W12-10 to W12-14 are located on the Exmouth Plateau, a deep-water marginal
plateau of the Northern Carnarvon Basin. The plateau hosts numerous giant to supergiant gas
fields, and has recently become Australia’s premier deep-water gas exploration province. Some of
the inboard gas fields are currently being developed or are in advanced stages of development
planning.
The plateau comprises a thick pre-rift section of block-faulted, Permo-Triassic sediments overlain
by thinner Jurassic–Lower Cretaceous syn-rift and thin, condensed, post-rift sediments. Top
Triassic fault blocks and their associated overlying drape features, as well as deeper intra-Triassic
cross-faults, provide numerous proven structural traps. Proven stratigraphic traps include Lower
Cretaceous basin floor fans and Upper Jurassic shoreface sandstones while Upper Triassic
pinnacle reefs represent a potential new play type.
.
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LOCATION
Release Areas W12-10 to W12-14 are located in deep to ultra deep water approximately 150 to
500 km off the coast of Western Australia on the Exmouth Plateau, within the Northern Carnarvon
Basin (Figure 1). The Release Areas are located to the west and southwest of the giant (~8 Tcf)
Scarborough gas field. The Release Areas do not contain any wells and water depths range from
about 850 to 4,500 m.
Release Area W12-10 is the largest area and consists of 195 graticular blocks covering
15,740 km2. Release Area W12-11 consists of 31 graticular blocks with a total area of 2,500 km2,
while W12-12 comprises 22 graticular blocks covering 1,770 km2, W12-13 comprises 21 graticular
blocks with an area of 1,685 km2 and W12-14 consists of 46 graticular blocks with a total area of
3,675 km2.
Gas production facilities are currently being developed for the Chevron operated Gorgon and
Io/Jansz fields and the Woodside operated Pluto field. Chevron has committed to developing the
Wheatstone LNG project at Ashburton North, and ExxonMobil and BHP Billiton are currently
examining development options for the Scarborough and Thebe fields.
The graticular block maps and graticular block listings for the Release Areas are shown in Figure 2.
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RELEASE AREA GEOLOGY
Local tectonic setting
The Exmouth Plateau is a deep-water marginal plateau that represents the westernmost structural
element of the Northern Carnarvon Basin (Figure 3). Most of the plateau is underlain by 10 to
15 km of generally flat-lying and tilted, block-faulted Lower Cretaceous, Jurassic, Triassic and older
sedimentary rocks (Figure 4). This succession was deposited during the periods of extension that
preceded breakup of Australia and Argo Land in the Middle Jurassic, and Australia and Greater
India in the Early Cretaceous (Stagg et al, 2004). The dominant fault trend on the Exmouth Plateau
is north–south, swinging to northeast–southwest near the northern and western margins of the
plateau and along the inner margin adjacent to the Rankin Platform and Exmouth, Barrow and
Dampier sub-basins (Figure 3)
Structural evolution and depositional history of the area
The Lower Triassic section in the Carnarvon Basin is marked by a regional marine transgression
that represents the sag phase of a previous Paleozoic rift cycle. The marine Locker Shale (below
TD of the wells on the Exmouth Plateau) unconformably overlies the Permian succession and
grades upwards into the Middle–Upper Triassic Mungaroo Formation (Figure 4). The Mungaroo
Formation was deposited in a broad, low relief, rapidly subsiding fluvio-deltaic coastal plain that
extended across the Exmouth Plateau. During marine transgression in the latest Triassic
(Rhaetian), carbonate patch reefs developed on the Wombat Plateau (von Rad et al, 1992a;
Williamson et al, 1989) and probably extended across the northern-and western-central parts of the
Exmouth Plateau, whereas marls, siltstones and thin sandstones (Brigadier Formation) were
deposited elsewhere.
As rifting proceeded between Australia and Greater India, several faulting episodes occurred in the
Jurassic. In the Pliensbachian, rifting inboard of the Exmouth Plateau formed the Exmouth, Barrow
and Dampier sub-basins. Several kilometres of marine Jurassic sediments, equivalent to
condensed sections on the central Exmouth Plateau (Dingo Claystone equivalents), were deposited
in these troughs. Major rift-fault movement occurred in the Callovian on the Exmouth Plateau with
oceanic crust created in the Argo Abyssal Plain in the late Oxfordian, and in the Gascoyne and
Cuvier abyssal plains in the Valanginian (Norvick, 2002). Rift and breakup volcanics are
widespread along the outer margins of the Exmouth Plateau (Figure 5) and probably include Upper
Triassic, Oxfordian to Callovian and Lower Cretaceous suites (Stagg et al, 2004).
During the Late Jurassic in the eastern Exmouth Plateau, sandy shelfal facies were deposited
within restricted shallow depocentres (including the Oxfordian Jansz Sandstone reservoir in the
supergiant Io/Jansz gas field). In the Early Cretaceous, the Barrow Group delta prograded
northward across the southern portion of the plateau to form a major sediment lobe with the shelf
edge arcing through or near the Investigator 1 and Zeepaard 1 well locations (Boote and Kirk,
1989). A distal claystone equivalent (Forestier Claystone) was deposited to the north of the delta
lobe. Barrow Group basin floor fans form the reservoir at the Scarborough gas field.
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As the newly formed oceanic crust of the Argo, Gascoyne and Cuvier abyssal plains rapidly
subsided, the Exmouth Plateau also foundered and was progressively transgressed throughout the
Cretaceous by shallow marine mudstone (Muderong Shale) and siltstone (Gearle Siltstone), midouter shelf marl and chalk (Toolonga Calcilutite), and finally Cenozoic bathyal chalk and ooze.
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EXPLORATION HISTORY
Two major exploration campaigns have focused on the deep-water Exmouth Plateau, the first in
1979 to 1980 for oil targets, and the second, currently underway, searching for gas. The initial
exploration programs were undertaken by Esso and Phillips (Barber, 1988) and eleven deep-water
(740–1,375 m) wells were drilled (Walker, 2007), targeting oil charge from the Jurassic Dingo
Claystone. Two wells were gas discoveries: Jupiter 1, a Triassic horst trap; and Scarborough 1, an
inverted Lower Cretaceous Barrow Group basin floor fan. At the time of the Scarborough 1
discovery (1979), the available technology and the undeveloped LNG market, made the remote,
deep-water gas accumulation uneconomic to develop. All other wells drilled during this period had
significant gas shows, but there were no oil discoveries.
The second phase of exploration commenced in the mid 1990s and focused on the established
Triassic fault-block play along the eastern margin of the Exmouth Plateau. Acreage on the northern
and western Exmouth Plateau was released in 2000, but failed to attract successful bids.
The supergiant Io/Jansz gas field was discovered with the drilling of Jansz 1 in 2000 and its lateral
extent realised with the drilling of Io 1 in 2001. This discovery represented a new Oxfordian play
type on the Exmouth Plateau (Jenkins et al, 2003). Following this discovery, gas became the
primary exploration target and extensive new acreage was awarded on the central, northern and
western Exmouth Plateau.
In 2007, BHP Billiton drilled Thebe 1 in Permit WA-346-P and discovered 2–3 Tcf (57–85 Bcm) of
gas (BHP Billiton, 2007; Anonymous, 2007). Thebe 2 (2008) was drilled 16 km to the north of the
initial discovery and confirmed expectations of the size and quality of the Thebe resource
(Jonasson, 2009).
Market conditions have changed markedly since exploration in the 1970s, with major gas trade
established with Japan, contracts to supply LNG to China, production facilities under construction
for Pluto and Gorgon, and development proposals for Scarborough and Thebe. In 2007, Hess was
awarded the deep-water petroleum exploration permit WA-390-P, located southwest of the
supergiant Io/Jansz field, with a 16 well drilling commitment. Thirteen of the 16 wells were gas
discoveries including Glencoe 1, Briseis 1, Nimblefoot 1, Lightfinger 1, Rimfire 1, Mentorc 1, Hijinx 1
and Glenloth 1. In the Glencoe 1, Briseis 1 and Nimblefoot 1 discoveries, accumulations occur
within the post-Callovian section, with Briseis 1 also encountering additional pay in the Triassic
Mungaroo Formation (Smallwood et al, 2010). The Oxfordian (W. spectabilis) sandstones
encountered in Glencoe 1 are analogous to those encountered at Io/Jansz. In contrast,
Nimblefoot 1 and Briseis 1 both encountered gas pay within deep-water Berriasian delta-front
turbidite sandstones sourced from the Barrow delta to the south, analogous to the Scarborough gas
field. Following their successful exploration campaign, Hess initiated an appraisal program in 2011
with the drilling and flow testing of several wells (Jonasson, 2011).
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Other recent gas finds have been made at Achilles 1 (2009), Satyr 1 (2009) and Sappho 1 (2010) to
the east; Martell 1 (2009), Yellowglen 1 (2009), Noblige 1 (2010), Larsen 1 (2010), Larsen Deep 1
(2010), Remy 1 (2010) and Martin 1 (2011) to the northeast; and Kentish Knock 1 (2009),
Guardian 1 (2009), Brederode 1 (2010) and Alaric 1 (2010) on the western Exmouth Plateau
(Figure 1). The discovery of gas at Brederode 1 (Chevron permit WA-264-P) and Alaric 1
(Woodside permit WA-434-P) significantly extends the western extent of known gas resources on
the Exmouth Plateau (Woodside, 2010a). Two commitment wells are scheduled to be drilled in late
2011 by Chevron (Vos 1 in permit WA-439-P; Jonasson, 2011) and Woodside (Cadwallon 1 and
Genseric 1 in permit WA-434-P; Woodside, 2011).
Well control
INVESTIGATOR 1 (1979)
Investigator 1 was drilled by Esso Australia Ltd to test the delta front sandstones of the Lower
Cretaceous Barrow Group in a large closure formed by a combination of northward depositional dip
on the delta front, regional south to southeast tilting of the Exmouth Plateau and gentle Cenozoic
arching about a northeast-trending axis (Figure 6; Esso Australia Ltd, 1980a). The well was drilled
in 841 m water depth and reached a TD of 3,745 mKB. It penetrated and sampled an Albian to
Barremian succession of claystone, marl and siltstone to 1,492 mKB, overlying a 1,748 m thick
section of basinal to prodelta and delta front claystone, siltstone and sandstone of the target Barrow
Group. The Barrow Group was underlain by a 15 m section of Upper Jurassic claystone, Middle to
Lower Jurassic marl (44 m), Upper Triassic (Rhaetian) marl (65 m) and Upper Triassic (Norian)
interbedded sandstone, siltstone, claystone and minor coal of the Mungaroo Formation (382 m thick
to TD). Sandstones of good reservoir quality occur within the Barrow Group (13–30% porosity), but
those within the Upper Triassic Mungaroo Formation were generally poor (5–16% porosity).
No significant hydrocarbon shows were recorded in the target Barrow Group reservoir, but elevated
mud gas levels and small amounts of wet gas and questionable oil films in wireline tests were
recorded in low permeability sandstones of the Mungaroo Formation. Log analysis indicates 4886% water saturation in these sandstones. The lack of hydrocarbons in the Barrow Group sands
was attributed to the absence of effective migration pathways for any hydrocarbons generated
within the deeper Mungaroo section.
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JUPITER 1 (1979)
Jupiter 1 was drilled by Phillips Australian Oil Company in water depths of 960 m to test a tilted
Triassic horst block. The well reached a TD of 4,946 mRT in a thick section of interbedded Triassic
siltstone, claystones, sandstone and minor coal and dolomite (A. reducta to S. quadrifidus
spore/pollen zones) of the Mungaroo Formation (Phillips Australian Oil Company, 1980). The well
penetrated 466 m of inferred calcareous ooze and marl of Holocene to Late Cretaceous age without
returns, and sampled Cretaceous chalk, calcareous claystone and siltstone to 1,857 mRT, and a
15 m section of Upper Jurassic claystone to 1,872 mRT. This Jurassic claystone was
unconformably underlain by 23 m of Upper Triassic (Rhaetian) carbonate and claystone, 39 m of
transgressive marine siltstone and sandstone (ascribed to the Brigadier Formation by Crostella and
Barter, 1980) and a thick section of Upper to Middle Triassic deltaic sediments of the Mungaroo
Formation (1,895–4,946 mRT). This is the maximum drilled thickness of Triassic section on the
Exmouth Plateau.
A 22.5 m gas column was discovered in Upper Triassic sandstones (1,911–1,933 mRT; Brigadier
Formation) with reserves of about 0.15 Tcf (4 Bcm; Walker, 2007). This accumulation has a strong
flat-spot direct hydrocarbon indicator (DHI) on seismic data, which indicates the spill-point of the
gas into the bounding fault, and venting through to a gas-chimney is also evident on seismic
(Barber, 1988).
SCARBOROUGH 1 (1979)
Scarborough 1 was drilled by Esso Australia Ltd to test a large, low relief anticline within the Barrow
Group delta that displayed a prominent flat-lying bright spot conforming to the crest of the structure
(Esso Australia Ltd, 1980b). The well was drilled in a water depth of 912 m and was abandoned at
a TD of 2,364 mKB due to mechanical problems. It penetrated an upper Campanian to Hauterivian
marl and claystone succession overlying pro-delta claystone and prograding submarine fan
sandstone of the Lower Cretaceous Barrow Group (total 683 m thick). Drilling was abandoned
within the Barrow Group, and the underlying Triassic section was not reached.
Scarborough 1 discovered a 59 m gas column within good quality sands (average 23% porosity) of
the lower Barrow Group basin floor fan sealed by prodelta claystone. Formation testing at
1,904.5 mKB recovered 5.2 m3 of methane with only 0.12% ethane and no fractions heavier than
propane.
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Several appraisal wells have been drilled; Scarborough 2 (1996) and Scarborough 3, 4 and 5
(2004–2005). Scarborough 2 was drilled to a TD of 2,068 mKB to appraise the southeast limit of the
lower delta fan reservoir discovery, and to confirm the presence of higher gas-bearing sands in the
upper delta fan with seismic amplitude anomalies (Esso Australia Ltd, 1997). A total of 84 m of
conventional core was cut in the upper and lower fans, and both successions were confirmed to be
gas bearing from log analysis, MDT samples and production testing. The upper fan reservoir
contained a 39 m gross gas interval with lower than expected porosity (20%), permeability (<10 mD) and gas saturation (49%). The lower fan reservoir contained a 28 m gross gas interval with
excellent porosity (26%), permeability (1,000–5,000 mD) and gas saturation (70%). Cores indicate
that the upper fan consists mostly of thin-bedded pelagic mudstone and debris-flow sands, whereas
the lower fan comprises amalgamated channel sands. Pressure gradients and gas compositions
suggest that the upper and lower fans are in communication, with the same gas-water contact as
Scarborough 1.
Scarborough 3 was located on the southwest flank of the structure to appraise the upper fan
complex of the Barrow Group. It encountered a 53 m gross gas column and demonstrated that
high-quality, amalgamated turbidite sands were developed in the upper fan (Gorter, 2005).
Scarborough 4 and 5 were drilled to further appraise the turbidite sandstones of the lower fan with
the upper fan sandstones a secondary objective. Scarborough 4 intersected 10.5 m of net gas pay
in the upper fan complex and 34.1 m in the lower fan complex while Scarborough 5 encountered
6.2 m and 36 m of net gas pay in these same units, respectively.
The Scarborough domal anticline, which was generated by structural inversion in the Campanian, is
approximately 350 km2 in area and contains reserves of about 8 Tcf (226 Bcm) of gas (BHP Billiton,
2008). ExxonMobil and BHP Billiton are currently assessing development options for Scarborough.
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VINCK 1 (1980)
Vinck 1 was drilled by Esso Australia Ltd in a water depth of 1,383 m to test a north and northwesttrending faulted anticline (Figure 7; Esso Australia Ltd, 1981a). The well reached a TD of
4,600 mKB within the Mungaroo Formation. No samples were collected down to 1,829 mRT and
the well intersected Hauterivian to Albian marl and calcareous claystone to 1,990 mKB (Gearle
Siltstone and Muderong Shale equivalents) overlying a 677 m thick section of Berriasian to
Valanginian Barrow Group sandstone, siltstone and claystone. The Barrow Group was underlain by
15 m of Upper Jurassic glauconitic siltstone, argillaceous or calcareous sandstone and marl (Dingo
Claystone equivalent), 45 m of Upper Triassic (Rhaetian to Norian) marl (Brigadier Formation
equivalent) and 1,873 m of Upper Triassic (Rhaetian to Norian) interbedded sandstones, siltstones
and claystones of the Mungaroo Formation. Sandstones of good reservoir quality occur within the
Barrow Group (30% porosity) and the Mungaroo Formation (16–25% porosity) although reservoir
quality in the Mungaroo Formation decreases considerably with depth (to 0–10% porosity at TD).
Significant hydrocarbon indications were only recorded in the Mungaroo Formation with 142 m of
net sands containing gas or gas and condensate. Testing was carried out on sandstones at
3,205.5 m, 3,206 m, 3,606 m and 3,798.5 m and recovered varying quantities of gas, condensate
and filtrate.
EENDRACHT 1 (1980)
Eendracht 1 was drilled by Esso Australia Ltd to test Upper Triassic (pre-Rhaetian) reservoirs within
an elongate tilted horst block bounded to the west by a major normal fault (Figure 5 and Figure 6;
Esso Australia Ltd, 1981b). The well was drilled in a water depth of 1,354 m and reached a TD of
3,410 mKB within the Mungaroo Formation. It penetrated Paleocene to Albian calcilutites to
2,184.5 mKB, a thin Barremian to Hauterivian claystone (Muderong Shale equivalent) to
2,195 mKB, Lower Cretaceous prodelta siltstone and claystone (Barrow Group) to 2,344.5 mKB, a
condensed section of Upper to Lower Jurassic claystone (Dingo Claystone equivalent), Upper
Triassic (Rhaetian) marl to 2,419 mKB, and Upper Triassic shallow marine to deltaic siltstone,
claystone and sandstone of the Mungaroo Formation.
Four gas-bearing sandstones in the Triassic Mungaroo Formation were intersected over the interval
2,467–2,652 mKB, with a total net gas pay of 25.5 m. The maximum observed gas column was
44 m in a thin sandstone at 2,467 m; the three deeper gas sands were recognised pre-drill as
seismic amplitude anomalies.
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SIRIUS 1 (1980)
Sirius 1 was drilled by Esso Australia Ltd in 1,173.9 m water depth and reached a TD of
3,500 mKB. The well tested a large, low-relief anticline within the Lower Cretaceous Barrow Group
(Figure 7; Esso Australia Ltd, 1981c). The Triassic sandstones of the Mungaroo Formation were a
secondary target. No samples were collected down to 1,573.6 mKB and the well intersected Lower
Cretaceous claystone, calcareous ooze, marl and siltstone to 1,675 mKB (Toolonga Calcilutite,
Gearle Siltstone and Muderong Shale equivalents) overlying 1,213 m of deltaic Barrow Group
sandstone and siltstone. The Barrow Group was underlain by a 109 m thick section of Lower to
Upper Jurassic marl, biomicrite and siltstone (Dingo Claystone equivalent), 11 m of Upper Triassic
(Rhaetian) marl, sandstone and claystone and 492 m of Upper Triassic Mungaroo Formation
siltstone and sandstone. Reservoir quality sandstones were encountered in the Lower Cretaceous
Barrow Group (25–35% porosity) and Upper Triassic Mungaroo Formation (10–25% porosity)
although fewer reservoir quality sandstones were encountered in the Mungaroo Formation than
expected.
Gas shows were recorded in the Barrow Group (2,740–2,850 mKB) and Mungaroo Formation
(3,015–3,500 mKB). The Barrow Group test failed due to the lack of intra-Barrow Group seals
within the sandy Lower Cretaceous section.
JACALA 1 (1996)
Jacala 1 was drilled by BHP Billiton Petroleum Pty Ltd in 1,062 m water depth to a TD of
2,217 mRT. This well targeted oil in a large, simple, 4-way dip structure with the Valanginian
Zeepaard Formation delta front sandstones being the primary objective (BHP Billiton Petroleum Pty
Ltd, 2006). No samples were collected down to 1,670 mRT and the well intersected Cenozoic and
Lower Cretaceous calcilutite, argillaceous calcilutite, marl and calcareous claystone to 2,068 mRT
(Toolonga Calcilutite, Gearle Siltstone and Muderong Shale equivalents) overlying 4 m of
Hauterivian glauconitic sandstone (Birdrong Formation) and 45 m of Early Valanginian sandstone
(Zeepaard Formation) to TD. The predicted Barrow Group sandstones were not reached. Reservoir
quality sandstones (average porosity of 30.5%) were encountered from 2,071.1 to 2,168 mRT in the
Zeepaard Formation but were 100% water saturated. No gas shows and only trace fluorescence
(top Zeepaard Formation) were recorded in Jacala 1. The failure of the well was attributed to a lack
of charge.
THEBE 1 (2007) AND THEBE 2 (2008)
Thebe 1 was drilled by BHP Billiton about 50 km north of the Scarborough gas field in 1,169 m
water depth. The well discovered a 73 m gas column (BHP Billiton, 2007) in a Triassic fault block
that may contain 2–3 Tcf (57–85 Bcm) of gas (Anonymous, 2007). Thebe 2 was drilled 16 km to the
north of the initial discovery and confirmed expectations of the size and quality of the Thebe
resource (Jonasson, 2009). Detailed results of the wells have not yet been released.
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KENTISH KNOCK 1 (2009), GUARDIAN 1 (2009)
Kentish Knock 1, located about 41 km southwest of Thebe 1, was drilled by Chevron Australia Pty
Ltd in 1,228 m water depth to a TD of 2,525 mRT (Chevron Australia Pty Ltd, 2010a). Guardian 1
was sidetracked from Kentish Knock 1 at a depth of 1,945 mRT. It reached at TD of 3,315 mRT.
The wells discovered a significant hydrocarbon column with 34 m of net gas pay (Chevron Australia
Pty Ltd, 2009; Jonasson, 2010). Detailed results of the wells have not yet been released.
BREDERODE 1 (2010)
Brederode 1, located approximately 17 km northwest of Eendracht 1, was drilled by Chevron
Australia Pty Ltd in 1,387 m water depth to a TD of 2,750 m. The well intersected 15 m of net gas
pay (Chevron Australia Pty Ltd, 2010b). Detailed results of the well have not yet been released.
TIBERIUS 1 (2010)
Tiberius 1, located about 24 km south of Alaric 1 and 73 km west of Eendracht 1, was drilled by
Woodside Energy Ltd in 1,660 m water depth to a TD of 2,856 m. The well tested an Upper Triassic
pinnacle carbonate reef play but due to lost circulation problems the well was abandoned
prematurely without penetrating the entire reef structure or Triassic section. No hydrocarbons were
encountered in the portion of the reef intersected (Woodside, 2010b). Detailed results of the well
have not yet been released.
ALARIC 1 (2010)
Alaric 1, located about 62 km west of Eendracht 1, was drilled by Woodside Energy Ltd in 1,961 m
water depth to a TD of 4,563 m. The well intersected approximately 185 m gross gas pay over
several zones within the Triassic sandstone target (Woodside, 2010b). Detailed results of the well
have not yet been released.
Further details regarding wells and available data follow this link:
http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20list_exmouthplateau_A
R12.xls
Data coverage
The Release Areas are covered by regional 2D seismic grids acquired in the late 1970s
(approximate 5 km line spacing) and 1991 to 1997 (line spacing of about 10–20 km). Deep seismic
data was acquired by Geoscience Australia in 1991–1995 across the central and northern Exmouth
Plateau (Surveys 101, 110, 128; Geoscience Australia, 2001), and across the outer margins of the
plateau (Surveys 135, 162; Stagg et al, 2004).
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In 2006 Chevron Australia acquired the Bonaventure 3D MSS (4,144 km2) across parts of permits
WA-364-P and WA365-P. The survey covers small sections of Release Areas W12-11 and W1212. In 2010, three surveys were conducted by Fugro, Woodside and Chevron. Fugro acquired the
large Eendracht 3D multi-client survey (~8,000 km2) which covers a small part of Release Area
W12-13 (Fugro Multiclient Services, 2010). Woodside Energy acquired the 3,771 km2 Claudius 3D
MSS over permit WA-434-P in late 2009 to early 2010 and Chevron Australia acquired the
1,867 km2 Agrippina 3D survey over WA-366-P and WA-439-P in 2010 (Jonasson, 2011).
In 2008, a new 2D multi-client survey (PGS New Dawn) was acquired across the Exmouth Plateau
including several lines over the Release Areas (Petroleum Geo-Services, 2009).
Seismic data are generally of high quality across the Exmouth Plateau, and indications of gas
charge and gas-water contacts can commonly be imaged directly as amplitude anomalies and flatspots.
In addition to commercial petroleum exploration wells, scientific Ocean Drilling Program (ODP)
wells have also been drilled on the Exmouth Plateau. In 1988, ODP Leg 122 (Haq et al, 1990; von
Rad et al, 1992b) drilled two wells on the western Exmouth Plateau (Figure 1) and four wells on the
northern Exmouth Plateau (Wombat Plateau). Detailed descriptions of the fully cored holes and
interpretation of the results are given by von Rad et al (1992b).
To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-and-promotion/2012.html#data-packages
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PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Sources
Triassic Mungaroo Formation (gas-prone)
Reservoirs
Lower Cretaceous basin floor fans and turbidites in the Barrow Group
Oxfordian upper–lower shoreface Jansz Sandstone
Upper Triassic (Rhaetian) reefs (no discoveries to date)
Upper Triassic shallow marine-deltaic Brigadier Formation
Top Triassic fluvio-deltaic Mungaroo Formation
Intra-Triassic fluvio-deltaic Mungaroo Formation
Seals
Lower Cretaceous marine Muderong Shale (regional seal)
Lower Cretaceous distal condensed claystones, Barrow Group (Forestier
Claystone equivalents)
Jurassic condensed marls/claystones (Dingo Claystone equivalents)
Intraformational Mungaroo Formation claystones (cross-fault)
Play Types
Tilted Triassic fault blocks and associated drapes
Oxfordian shoreface sandstone stratigraphic traps
Lower Cretaceous basin floor fan stratigraphic traps
Upper Triassic (Rhaetian) pinnacle reefs
Source rocks
The supergiant Io/Jansz gas field, giant Scarborough gas field, and the Jupiter 1 and Eendracht 1
gas discoveries, together with the recent gas discoveries in the Chandon 1, Thebe 1 and 2,
Martin 1, Kentish Knock 1/Guardian 1, Brederode 1 and Alaric 1 wells, demonstrate that the deepwater Exmouth Plateau is prospective for large gas discoveries. All these discoveries are attributed
to a widespread regional gas system sourced from the Triassic succession.
The thick Triassic and older sedimentary section on the Exmouth Plateau has the greatest potential
for mature source rock facies, with possible organic-rich units in the Lower Triassic (marine Locker
Shale equivalents) and Upper Triassic (deltaic Mungaroo Formation facies and marine equivalents).
Recent exploration activities on the Exmouth Plateau are based on a model that invokes gas
charge from the deeply buried coal and carbonaceous claystone of the Mungaroo Formation. Peak
gas generation from these Triassic source rocks is interpreted to be occurring now at depths
greater than 5 km subsea (Bussell et al, 2001).
Organic-rich sediments may also be present within the condensed Jurassic and Upper Cretaceous
succession, but these are immature.
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Reservoirs
Fluvio-deltaic sandstones of the Upper Triassic Mungaroo Formation (e.g. Eendracht 1 and
Chandon 1) and basin-floor fan and turbidite sandstones of the Lower Cretaceous Barrow Group
(e.g. Scarborough field, Nimblefoot 1 and Briseis 1 shallow) provide good quality reservoirs across
the Exmouth Plateau and are likely to represent the main reservoir target within the Release Areas.
Transgressive marine sandstones of the Brigadier Formation (e.g. Jupiter 1) and Rhaetian reefal
carbonates (Tiberius 1; Woodside, 2010b) provide additional potential reservoir targets.
Seals
Fine-grained deep-water Cretaceous sediments (Muderong Shale and distal facies of the Barrow
Group) provide a regional seal across the Exmouth Plateau. There are also intraformational seals
within the deltaic sequences of the Upper Triassic Mungaroo Formation. The Rhaetian marl and
Jurassic condensed marls/claystones (Dingo Claystone equivalents), where preserved, can also
provide a top seal to Triassic reservoirs.
Play types
High relief top Triassic fault blocks together with associated drape features and deeper intraTriassic cross-fault traps provide numerous potential structural traps on the Exmouth Plateau
(Figure 8). Upper Triassic (Rhaetian) pinnacle and patch reefs (such as those intersected in ODP
holes on the Wombat Plateau; Williamson et al, 1989) have been identified as potential new plays
across parts of the central Exmouth Plateau. Woodside unsuccessfully tested one of these plays
with Tiberius 1, which was drilled in WA-434-P in 2010 (Woodside, 2010b). Other proven
stratigraphic traps in the region include Lower Cretaceous basin floor fans (e.g. Scarborough field)
and Upper Jurassic shoreface sandstones (e.g. Io/Jansz field, Glencoe 1).
Critical risks
A proven hydrocarbon system has been established across the Exmouth Plateau although the full
extent of the system, particularly in the north and west, is yet to be determined. Continued
exploration success on the Exmouth Plateau relies on the identification of additional valid traps with
access to charge from the gas-prone Mungaroo source. 3D seismic and AVO technology are thus
key exploration tools that are likely to contribute to continued exploration success on the deepwater Exmouth Plateau (Longley et al, 2002; Korn et al, 2003; Williamson and Kroh, 2007).
www.petroleum-acreage.gov.au
14
FIGURES
Figure 1
Location map of Release Areas W12-10, W12-11, W12-12, W12-13 and W12-14,
on the Exmouth Plateau, Northern Carnarvon Basin. Exploration wells relevant to
the Release Areas are also shown.
Figure 2
Graticular block map and graticular block listings for Release Areas W12-10,
W12-11, W12-12, W12-13 and W12-14, on the Exmouth Plateau, Northern
Carnarvon Basin.
Figure 3
Structural elements of the Exmouth Plateau showing the 2012 Release Areas,
hydrocarbon accumulations and discoveries. The location of seismic lines in
Figure 5, Figure 6 and Figure 7 are shown.
Figure 4
Stratigraphy and hydrocarbon discoveries of the Exmouth Plateau, based on the
Northern Carnarvon Biozonation and Stratigraphy Chart (Nicoll et al, 2010).
Geologic Time Scale after Gradstein et al (2004) and Ogg et al (2008). Regional
seismic horizons after AGSO (2001).
Figure 5
AGSO seismic line 135/01 across Release Area W12-10 on the western
Exmouth Plateau. The location of the seismic line is shown in Figure 3. Regional
seismic horizons are shown in Figure 4.
Figure 6
AGSO seismic line 110/12 across Release Area W12-12 on the central Exmouth
Plateau. The location of the seismic line is shown in Figure 3. Regional seismic
horizons are shown in Figure 4.
Figure 7
Seismic line CT93/421ab across Release Areas W12-13 and W12-14 on the
southern Exmouth Plateau. The location of the seismic line is shown in Figure 3.
Regional seismic horizons are shown in Figure 4.
Figure 8
Play types on the Exmouth Plateau (modified from Woodside, 2009). Lower
Cretaceous Barrow Group basin floor fan and turbidite plays (e.g. Scarborough,
Nimblefoot and Briseis shallow) not shown.
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