PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREA W11-15,
EXMOUTH SUB-BASIN, NORTHERN CARNARVON
BASIN
WESTERN AUSTRALIA
Bids Close – 13 October 2011

Adjacent to Australia’s major new oil producing province

Proven Locker/Mungaroo–Mungaroo/Barrow and Dingo–Barrow
petroleum systems

Barrow Group and Tithonian canyon plays within the Release Area

Proven Triassic fault block gas play in adjacent acreage

Complete 3D seismic coverage

Special Notices apply, refer to Guidance Notes
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 1 of 24
LOCATION
Release Area W11-15 is located in the northern Exmouth Sub-basin,
approximately 85-120 km offshore from the township of Onslow (Figure 1).
Water depths vary from 200 to 600 m.
Release Area W11-15 comprises 9 graticular blocks with a total area of
720 km 2. The graticular block map for the Release Area is shown in Figure 2.
Release Area W11-15 is located about 20 km northeast of the new oil
province discovered in the Exmouth Sub-basin. Oil production started from
the Woodside operated Enfield field in 2006 using a floating production,
storage and offloading system, the Nganhurra FPSO. Production commenced
in 2007 from the BHP Billiton operated Stybarrow development (Stybarrow
FPSO) and in 2008 from the Woodside operated Vincent project (Maersk
Ngujima-Yin FPSO). More recently, two new oil projects from this province
started production in 2010 (Figure 2) in Regional Geology of the Northern
Carnarvon Basin. The Pyrenees project achieved first production of heavy
sweet crude oil with an estimated production life of 25 years; and the Apache
operated Van Gogh development, part of the greater Vincent oilfield
(Gascoyne Development Commission Offices, 2010). Domestic gas
production is also expected from 2013 from the offshore Macedon gas field,
using a new gas plant at Ashburton North, 17 km southwest of Onslow and
via a connection to a pipeline between Dampier and Bunbury (Oil & Gas
Journal, 2010). The pipeline linking the Griffin FPSO to the Tubridgi gas field
onshore is located only 25 km east of the Release Area (Figure 1).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 2 of 24
RELEASE AREA GEOLOGY
The geological evolution of the Northern Carnarvon Basin, and the Exmouth
Sub-basin in particular, has been discussed in detail by many authors, and
the summary presented below is derived from the work of Veevers (1988),
Hocking (1990), Arditto (1993), Jablonski (1997), Tindale et al (1998), Bussell
et al (2001), Norvick (2002), Longley et al (2002), Smith et al (2003) and
Scibiorski et al (2005).
Local Tectonic Setting
Release Area W11-15 is located in the northern Exmouth Sub-basin. The
north–south-trending Triassic high of the Alpha Arch marks the eastern
boundary of the Exmouth Sub-basin and separates it from the Barrow Subbasin (Figure 3). The western margin of the Exmouth Sub-basin is bounded
by northeast–southwest-trending Resolution Arch, which separates the subbasin from the broad, faulted Triassic platform of the Exmouth Plateau.
Development of the Resolution Arch commenced during the Campanian and
was enhanced during the Oligocene and possibly the Miocene. The rapid
inversion along the Resolution Arch created a zone of instability, resulting in
significant slumping and channelling over the western Exmouth Sub-basin
and possibly over the Release Area. The Release Area is located in the
northern end of the main depocentre, between the Alpha Arch and the
Resolution Arch, to the northeast of the west-northwest to east-southeasttrending Novara Arch. Development of this latter structure commenced in the
early Santonian and continued into the Oligocene, overprinting, reactivating
and causing the erosion of earlier Valanginian structures. To the south of the
Novara Arch, the east-northeast–west-southwest trending Ningaloo Arch
formed during the Valanginian uplift, reactivating Triassic to Jurassic faults
(Figure 3).
Structural Evolution and Depositional History of the Sub-basin
Along with the Barrow, Dampier and Beagle sub-basins, the Exmouth Subbasin formed as a series of northeast–southwest-trending, en echelon
structural depressions during the Pliensbachian to Oxfordian (Tindale et al,
1998; Smith et al, 2003; Scibiorski et al, 2005). These sub-basins are Jurassic
depocentres representing a failed rift system that developed during the early
syn-rift phase of breakup of the northwestern Australian continental margin.
The pre-rift section in the Exmouth Sub-basin consists of a sequence of
Permian and Lower to Middle Triassic sediments. Pennsylvanian (late
Carboniferous) to Early Permian rifting and subsequent Triassic thermal
subsidence resulted in the formation of a wide basin. The Locker Shale was
deposited in shallow shelf environments during a widespread Early Triassic
marine transgression which is recognised all along the Western Australian
margin from the Bonaparte Basin to the Perth Basin (Figure 4). The Locker
Shale is overlain by a thick succession of mainly fluvio-deltaic to marginal
marine sediments of the Mungaroo Formation (Figure 4; Tindale et al, 1998).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 3 of 24
A narrow basin, formed during Early-Middle Jurassic rifting between Australia
and Greater India, resulted in the deposition in an open marine environment
of the Dingo Claystone, the main source rock of the region (Figure 4).
Extensional reactivation followed in the Late Jurassic and Early Cretaceous
as Greater India separated from Australia. Rift-related uplift to the south of the
Exmouth Sub-basin provided the sediment source for the main reservoir units
in the area. These lie within the Barrow Delta which prograded northward over
the Exmouth Sub-basin and the southern and central Exmouth Plateau. The
delta had covered the Alpha Arch by the mid-Berriasian (Smith et al, 2003)
and extended into the Barrow Sub-basin as far as the southern end of the
Gorgon field (Figure 3). Northeast–southwest-trending syn-sedimentary faults
affect the Barrow Group sediments and can provide local combined structural
and stratigraphic traps.
Continued separation of Greater India from Australia in the Valanginian
(Veevers, 1988) is correlated with major structural inversion which resulted in
the uplift of the Ningaloo Arch, with associated erosion of the Barrow Group
and older Jurassic sediments across much of the sub-basin (Figure 4 and
Figure 5a; Tindale et al, 1998). The delta sediments were reworked and redeposited in the parasitic deltaic wedges of the Zeepaard and Birdrong
formations (Figure 4; Arditto, 1993; Tindale et al, 1998). This event is
associated with the development of structural dip to the north by tilting of the
east-west trending Ningaloo Arch to the south. This resulted in the formation
of complex trapping architecture within the Late Berriasian arch that extends
in a north-northeast direction across the western edge of the sub-basin (e.g.,
Eskdale structure).
A regional marine transgression during the Hauterivian marked the beginning
of thermal relaxation during the post-rift stage, and resulted in the deposition
of the main regional seal for the Carnarvon Basin, the Muderong Shale
(Figure 4). This formation thins to the south of the Release Area where it
onlaps the Ningaloo Arch, which was a positive feature at the time of
deposition (Tindale et al, 1998). The Muderong Shale is overlain by the
Windalia Radiolarite, a porous but low permeability thief zone. Above the
radiolarite, the Lower Gearle Formation, which consists of a thick sequence of
Albian to mid-Cenomanian claystones and siltstones, is deposited in an outershelf environment and is considered to be an effective top seal for some
accumulations in the sub-basin (e.g., Pyrenees and Macedon fields; Bailey et
al, 2006).
Basin inversion and uplift in the Late Cretaceous formed the Novara Arch and
the Resolution Arch (Figure 3) and shut down the Jurassic source ”kitchen”.
Uplift began in the early Santonian and overprinted and reactivated previously
formed structures (Tindale et al, 1998).
The latest phase of tectonism is recorded in the Late Miocene by gross tilting
of the margin to the west due to progradation of a thick Tertiary carbonate
wedge and fault reactivation. During this interval, a renewed phase of
compression enhanced the Pyrenees/Macedon structure and is interpreted to
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 4 of 24
have tilted many structures to the south and west and is likely to have
modified existing hydrocarbon accumulations (Tindale et al, 1998).
The Upper Cretaceous to Holocene passive margin sedimentary section in
the Exmouth Sub-basin is dominated by deep-water fine-grained carbonate,
including calcilutite and marl (Figure 4).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 5 of 24
EXPLORATION HISTORY
The first flow of oil to the surface in Australia was recorded in 1953 at Rough
Range 1 in the onshore Northern Carnarvon Basin, immediately east of the
Exmouth Sub-basin. However, further drilling on the same structure, a surface
anticline located to the south of Exmouth Gulf, could not replicate the initial
success of Rough Range 1, which recorded an oil flow of 500 bopd
(79.5 kL/d) from the Lower Cretaceous Birdrong Sandstone (Bradshaw et al,
1999; Ellis and Jonasson, 2002).
Exploration in the Exmouth Sub-basin has been episodic over the last 35
years. The area did receive some attention during the first phase of island and
shallow water drilling by Western Australian Petroleum Pty Ltd (WAPET) in
the 1960s and early 1970s (Mitchelmore and Smith, 1994). The first gas
shows were recorded in 1972 when West Muiron 1 was drilled on the feature
later recognised as hosting the Pyrenees/Macedon gas and oil accumulation.
This indicated that the Exmouth Sub-basin was petroliferous. However, the
focus of exploration was elsewhere in the Carnarvon Basin, namely in the
Barrow and Dampier sub-basins, where giant discoveries were made
including a billion barrels (1.59 x 108 kL) of oil-in-place at Barrow Island in
1964 and multi-Tcf (>5 x 10 10 m 3) gas fields on the Rankin Platform in 1972.
In the late 1970s and early 1980s, exploration in the region concentrated on
deepwater drilling on the Exmouth Plateau. These initial exploration programs
on the plateau were undertaken by Esso and Phillips (Barber, 1988) and
resulted in the giant gas discovery at Scarborough (Walker, 2007).
The general offshore exploration focus around Australia moved inboard in the
early 1980s, as permit sizes and prospect volumes within the permits
decreased. In the shallow water section of the Exmouth Sub-basin, Jurabi 1
was drilled by Esso Australia Ltd in 1982 as another test of the West Muiron
structure. However, this failed to intersect a significant hydrocarbon column
and it was not until the 1990s that there was eventual success on this
structure (Mitchelmore and Smith, 1994).
Eight deep-water wells were drilled in the southern Exmouth Sub-basin
between 1999 and 2004, following the 1998 Vincent 1 oil discovery. The
discovery in 1999 of the Enfield oil field followed by a string of oil discoveries,
including Coniston, Laverda, Stybarrow, Ravensworth and Stickle increased
interest in this sub-basin. A new oil province had been discovered. This
drilling program was very successful, due to extensive quantitative
interpretation of 3D seismic data, resulting in the numerous oil and gas
discoveries (Walker, 2007). Combined initial production of major fields,
including Enfield, Vincent, Pyrenees, Stybarrow and Laverda, indicates the
province contains more than 48 GL (300 MMbbl) of heavy crude reserves.
These are the most important oil development projects from Western Australia
in the past five years. Production is estimated to approach 40,000 kL/d or
250,000 bbl/d (2008). Two new oil projects commenced in 2010; production
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 6 of 24
from the Van Gogh oilfield started in February and production from the
Pyrenees project comprising the Crosby, Ravensworth and Stickle oilfields
started in February-March 2010 (Department of Mines and Petroleum, 2010).
Well Control
Resolution 1 (1979)
Resolution 1 was drilled by Esso Australia Ltd to test a Triassic Mungaroo
Formation objective in a narrow, northeast-trending, faulted horst on the
northwestern margin of the Exmouth Sub-basin. The well encountered
reservoir quality sandstones in the Mardie Greensand, Barrow Group and
Mungaroo Formation. The Dingo Claystone and Mungaroo Formation were
identified as potential source rocks, with average TOC values of 2.36% and
2.53%, respectively. On well logs, a thin (2.5 m) and tight gas-bearing
sandstone was identified at the top of the Mungaroo Formation. There was no
closure at the Barrow Group level and no significant hydrocarbons were found
at this level. No shows were recorded in sands of the Mardie Greensand
Member. A seal was identified in the Dingo Claystone equivalent. The
Muderong shale is not intersected in Resolution 1. A local heating event prior
to the deposition of the Upper Jurassic sequence is interpreted from available
data. A rapid early coalification in the Triassic was followed by significant
erosion removing at least 500 m of section (Esso Australia Limited, 1980).
The lack of significant hydrocarbons in the Resolution structure was attributed
to overpressuring in the Mungaroo Formation transmitted from the Dingo
Claystone, prior to thermal maturation of the source rock (Esso Australia
Limited, 1980).
Zeepaard 1 (1980)
Zeepaard 1 was drilled by Esso Australia Ltd to test a narrow Triassic
northeast-trending faulted horst in the northern edge of the Exmouth Subbasin. Closure is provided to the west and north by a bounding fault which
curves round to an east-west strike. Closure to the southeast is provided by
dip of the beds towards the Exmouth depocentre. Possible erosion along the
northern flank of the horst may have provided independent closure. The
second objective was to evaluate the hydrocarbon potential of a Lower
Cretaceous turbiditic sandstone stratigraphic trap. The well reached a TD of
4,214.8 m RKB. Good reservoirs were encountered in the Barrow Group and
Mungaroo Formation equivalent. Two gas sands were interpreted in the
Mungaroo Formation equivalent from electric logs, with average porosity of
14.5% and 10.6%, respectively. A possible third gas sand is interpreted in
between. Residual hydrocarbons were found in the Barrow Group. The Lower
Barrow Group and Dingo Claystone have good oil source potential, while the
Mungaroo Formation equivalent could source both gas and oil. Reworked
Triassic coals in the Dingo Claystone are also identified as a potential source.
The Dingo Claystone and delta front siltstones of the Barrow Group and the
Muderong Shale provide good seals. The lack of fluid movement into the horst
trap resulting from over-pressuring in the Dingo Claystone may have
preserved initial porosities (Esso Australia Ltd, 1981).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 7 of 24
Vlaming Head 1 (1982)
Vlaming Head 1 was drilled by CNW Oil (Australia) Pty Ltd to test a large
stratigraphic pinch-out structure in the Barrow Group on a northeastsouthwest trending structural nose. The primary objective was encountered
lower than predicted beneath the Muderong Shale and the Birdrong
Sandstone and the predicted basal seal was instead the top of the Barrow
Group. The well was deepened but no significant shales were intersected
below the lower Barrow Group sands. The primary objective lacks a basal
seal and the secondary objective an upper seal. The absence of seals
resulted in the Barrow Group reservoirs being 100% water wet. The well was
plugged and abandoned.
West Muiron 3 (1992)
The West Muiron structure (Pyrenees/Macedon fields) is a large antiform,
dissected into a series of tilted fault blocks by several northeast–southwest
trending faults. The prospect is in the Lower Cretaceous at the base of the
Muderong Shale, overlying a deep Triassic high trend, the southerly extension
of the Alpha Arch. West Muiron 1 and 2 were drilled by WAPET in 1972 and
1975 respectively, targeting the Lower Cretaceous sequence that was
hydrocarbon-bearing at Barrow Island. West Muiron 1 was abandoned due to
mechanical difficulties, while West Muiron 2 encountered no shows in the thin
Barrow Group intersection. West Muiron 3 was drilled by BHP Petroleum in
1992, 3 km to the northwest of West Muiron 2, to test Birdrong Formation and
Barrow Group sandstones within the West Muiron structure. West Muiron 3
well reached a TD of 1,200 mRT. The Birdrong Formation was absent, but the
well intersected a 40 m dry gas column in highly porous and permeable
unconsolidated sands of the Berriasian Barrow Group (Mitchelmore and
Smith, 1994). An average porosity of 31% and gas saturation of 88% are
calculated (BHP Petroleum Pty Ltd, 1994 a). The seal for these units is
provided by the Muderong Shale and Lower Gearle Formation. A gas-bottom
seal contact prevented an accurate assessment of the potential hydrocarbon
column. The presence of gas is also reported in the Windalia Radiolarite but
permeabilities are very low. The West Muiron 4 step-out well, drilled by BHP
Petroleum in 1993, established a total gas column in the Barrow Group in
excess of 91 m. The gas field discovered in West Muiron 3 was later named
the Macedon gas field. Langdale 1 (2005) was drilled north of the Macedon
gas field to evaluate the hydrocarbon prospectivity of the Berriasian Pyrenees
Member (basal Barrow Group) in a combination structural-stratigraphic trap
on the Langdale West fault block but did not achieve the principle objective as
gas-bearing sands of variable quality were intersected instead of the
prognosed oil-bearing sands. Helvellyn 1 (2007), drilled north of Langdale 1,
failed to encounter commercial quantities of hydrocarbons (Department of
Mines and Petroleum, 2008).
BHP Billiton, operator with Apache Corporation will commence production of
natural gas from the offshore Macedon gas field with four wells tied to a new
gas plant onshore (BHP Billiton, 2010). The field is 100 km west of Onslow on
production license WA-42-L. First production is expected during 2013. BHP,
with a 71.43% interest, estimates reserves at 400-750 bcf of recoverable wet
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 8 of 24
gas and a total project cost of $1.5 billion. Apache holds the remaining
interest. The gas plant will be built at Ashburton North, 17 km southwest of
Onslow. From the plant, gas will flow via a sales pipeline connected to a
pipeline between Dampier and Bunbury (Oil & Gas Journal, 2010).
West Muiron 5 (1993)
Pressure data acquired in previous West Muiron wells allowed for the
possibility of an oil leg underlying the discovered gas, therefore the West
Muiron structure was further appraised with the drilling of West Muiron 5 by
BHP Petroleum (Mitchelmore and Smith, 1994). West Muiron 5 was drilled
5.7 km west-southwest of West Muiron 4 to test the downthrown fault block
forming the western flank of the structure, which was closest to the interpreted
oil migration direction and still within structural closure. The well encountered
a 20 m thick column of dry gas overlying a 32 m thick column of 18 API oil
within the Berriasian Barrow Group (BHP Petroleum Pty Ltd, 1994 b).
Compositional variations of the gas, separate hydrocarbon contacts and minor
pressure differences between West Muiron 5 and West Muiron 3 and 4 are
indicative of two distinct fields. The oil and gas field discovered in West
Muiron 5 was later named the Pyrenees oil and gas field. Both the gas and oil
were biodegraded but producible, especially in high quality reservoirs (Smith
et al, 2003). Residual hydrocarbon was found in the Windalia Radiolarite.
York 1 (1993)
York 1 was drilled by BHP Petroleum Pty ltd to test the Birdrong Sandstone
on an unfaulted depositional drape anticline with four-way dip closure and
15 m vertical relief, overlying an older Triassic–Jurassic horst block. The time
closure is lacking due to lateral velocity variations in the Tertiary carbonates,
“pulling-up” the eastern flank of the structure, however, depth conversion
indicated a closure at the York location. York 1 well reached a TD of
3,372 mRT in a water depth of 365 m. Good reservoir sandstones with high
net-to-gross ratios were intersected in the Birdrong and underlying Zeepaard
Formation of the Barrow Group. The Birdrong Sandstone has core plug
porosities of 15 to 20% and permeabilities of up to 3,000 mD. The well
intersected the entire Zeepaard Formation and bottomed in the upper Barrow
Group, without encountering significant hydrocarbon shows (BHP Petroleum
Pty Ltd, 1994 c). This well did not attempt to drill into a deeper target of
possible slope fan sandstones that may form stratigraphic traps in the intraBarrow Group on the York structure.
Altair 1 (1995)
Altair 1 was drilled by West Australian Petroleum Pty Ltd to test a turbidite
sandstone pinch-out within the deltaic bottom-set unit (Malouet Formation) of
the Barrow Group. This was a pure stratigraphic trap test on a monoclinal
structure, based solely on a strong seismic amplitude anomaly. The well
intersected sandstone with excellent reservoir properties, but the sandstone is
water-bearing. The top seal is provided by progradational prodeltaic shales
over a turbiditic reservoir. The bottom seal is provided by the underlying
transgressive and highstand condensed pelagic shales. A wireline formation
test recovered water and a tiny quantity of solution gas from the sandstone. A
sharp lithological contrast is likely the cause of the amplitude anomaly. It was
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 9 of 24
concluded that gas was once present in the Altair Sand and probably in the
Paleogene, during inversion folding, the hydrocarbons were lost.
Subsequently, the sands were not recharged nor the trap re-established. This
suggests that potential for recharge by hydrocarbons matured during the Late
Cenozoic must be carefully evaluated in the area (West Australian Petroleum
Pty Ltd, 1995).
Vincent 1 (1998)
Vincent 1 was drilled by Woodside in 379 m water depth on the flank of the
Novara Arch trend, to test a three-way dip/fault closure at the base of the
Muderong Shale. Vincent 1 encountered hydrocarbon-bearing sandstones in
the Lower Barrow Group objective, with an 8 m gas leg and a 19 m oil leg.
The well was tested, achieving maximum flow rates of 4,301 bopd
(683.8 kL/d), with 1.9 MMscf/d (53,808 m3/d) gas through a 2” choke. The API
gravity of the oil was 17°. H 2 S gas was detected during the test, reaching a
maximum of 80 ppm. The excellent quality of the reservoir encountered in
Vincent 1 is the primary reason for the good test result and it is clear that
reservoir quality is a key factor for prospects with a similar hydrocarbon
charge. The Vincent oil discovery at the top of the Barrow Group is significant
in that it proved producible oil in an area where oil was previously considered
to be too biodegraded and heavy to produce (Polomka et al, 1999). The
Vincent 1 well became the harbinger of successful exploration drilling
campaigns in this area. Van Gogh is the name given to the northern part of
Vincent field where production commenced in February 2010. Van Gogh is
Apache’s first oil development using a floating production, storage and
offloading (FPSO) system, the Ningaloo Vision. The project is expected to
produce 6,360 kL/d (40, 000 bbl/d) of oil (Department of Mines and
Petroleum, 2010).
Enfield 1 (1999)
Enfield 1 was drilled by Woodside to test a terraced fault block on the western
flank of the Novara Arch. Enfield 1 intersected a gross 21.9 m oil column in
the primary objective, Macedon Formation sandstones, at 2,022.3 mRT, and a
gross gas and oil column of 14.8 m at 1,478.3 mRT in the secondary
objective, the Lower Cretaceous Barrow Group–Mardie Greensand Member.
The well reached a total depth of 2,192 mRT in the Dingo Claystone. A
production test, carried out within the Macedon Formation, achieved a
maximum stabilised flow rate of 4,800 bopd (763.1 kL/d) through a 44/64”
choke (Woodside, 1999). Enfield 1 was drilled in 544 m of water and had
128 MMbbl (2.035 x 10 7 kL/d) in initial reserves. The well came into
production in 2006 and was the first field to do so in the Exmouth Sub-basin
(Walker, 2007).
Coniston 1 (2000)
Coniston 1 was drilled in 415.5 m of water by BHP Petroleum Pty Ltd to
evaluate the hydrocarbon prospectivity of the upper Berriasian shoreface
sands of the Barrow Group within the large, fault-dissected, domed anticline
that was also tested by Novara 1 in 1982. Petrophysical interpretation of the
well showed that Coniston 1 intersected an 11.5 m gas column over a 13 m oil
column within the Barrow Group sands. However, in contrast to Novara 1,
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 10 of 24
Coniston 1 achieved a flow of 2,119 bopd (336.9 kL/d) from a 13 m oil column
below 11.5 m of gas (Smith et al, 2003). Early Cretaceous migration of oil into
the Novara structure appears to have been modified during the Late
Cretaceous compressional tectonism that created the Novara Arch, and on
which the broad Coniston anticline is developed. The 18 m residual oil column
intersected in Novara 1 is interpreted to be the result of spillage into the newly
developed Coniston structure. The base of the present-day oil column in
Novara 1 coincides with the spill point into the Coniston structure. The latter,
then, is substantially under-filled (and with an oil–water contact approximately
10 m above the Novara oil–water contact) due to inadequate spilled
hydrocarbons available to fill the trap. In addition, little fresh oil was expelled
and migrated from the Exmouth Sub-basin following Late Cretaceous uplift of
the source rocks into a much cooler thermal regime. Reburial of Jurassic
source rocks into the generative zone, due to deposition of Pliocene to
Holocene carbonates, has contributed a minor thermal gas charge that has
displaced the oil pool downwards to its present level (Smith et al, 2003).
Crosby 1 (2003)
Crosby 1 was drilled by BHP Billiton to test the validity of an elongate, northnortheast-trending structural–stratigraphic trap located on a northeast trending
fault terrace between the Ravensworth and the West Muiron 5 oil and gas
discoveries. The primary objective was the shallow marine uppermost
Tithonian to lower Berriasian Pyrenees Member of the Barrow Group. The
well reached a total depth of 1,226 mRT. Wireline log analysis indicated that
the primary reservoir was oil-bearing, with 34.0 m of net oil pay. This was
confirmed by RCI pressure testing and fluid recovery, with good quality
samples of 18.6°API oil obtained from the Pyrenees Member. Geochemical
analysis of the Crosby 1 oil and gas indicates that the accumulation
represents a mixture of an early charge of oil and associated gas, a later
charge of mature wet-gas/condensate (including gasoline-range
hydrocarbons), and a late charge of very mature dry gas, all of which were
subsequently biodegraded (BHP Billiton, 2004).
In February and March 2010, the Pyrenees project, comprising the Crosby,
Ravensworth and Stickle oilfields, started production ahead of schedule in the
BHP Billiton Petroleum operated permit WA-42-L. The full project includes a
subsea gathering system and the Pyrenees Venture FPSO vessel capable of
producing up to 15,263 kL (96,000 bbl) of oil and reinjecting 1.7 Mm 3
(60 MMscf) of gas per day. Gas produced by the development will be
reinjected into the reservoir of the nearby Macedon gasfield for future
recovery (Department of Mines and Petroleum, 2010).
Eskdale 2 (2004)
Eskdale 1 and 2 were drilled by BHP Billiton in 2003 and 2004, respectively,
to test the hydrocarbon potential of a complex structural/stratigraphic channel
trap beneath the collapsed core of the north-northeast-oriented late Berriasian
Resolution Arch. The trap is defined by sand distribution within a midTithonian submarine canyon-fill complex that is dissected by the cross-cutting
Berriasian–Valanginian structural dip and fault components. Eskdale 1
encountered a residual oil column within the target Dupuy Formation.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 11 of 24
Eskdale 2, located approximately 2 km south of the Eskdale 1, intersected a
36.9 m thick gas- and oil-bearing sandstone succession in the Dupuy
Formation, with a 24 m gas leg and a 12.9 m oil leg (BHP Billiton, 2005). An
oil–water contact was not penetrated but extrapolation of MDT pressure data
suggests a total oil column of 49.2 m. Modelling suggests that the Oxfordian
basal Dingo Claystone is the likely source rock, and although the Dingo
Claystone is capable of generating both oil and gas, the majority of the gas is
likely the result of biodegradation of trapped oil (biogenic methane). The oil
discovered in Eskdale started production in 2007 as part of the BHP Billiton
(operator) and Woodside Stybarrow project. Stybarrow Project produced
11.40 million barrels of crude oil during 2009 and has a current capacity of
11.97 million barrels per year. The field life of Stybarrow Project is expected to
be around 10 years with complete abandonment by September 2016. The
field is expected to generate $3.73 billion in revenue (undiscounted) during its
remaining life, starting 1/1/2010 (Articles Hub, 2010).
Beg 1 (2007)
Beg 1 was drilled by Apache Northwest Pty Ltd less than 5 km southwest of
the Acreage Release area and discovered hydrocarbons (Department of
Mines and Petroleum, 2008). The well was drilled in 345 m of water (below
AHD) and reached a total depth of 3,936 mMDRT (Apache Energy, 2008). No
further data is publicly available at the time of writing.
Bleaberry West 1 (2007)
Bleaberry West 1 well was drilled by Apache Energy about 25 km southwest
of the Release Area and discovered hydrocarbons (Department of Mines and
Petroleum, 2008). No further data is publicly available at the time of writing.
For further details regarding wells and available data follow this link:
http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20li
st_exmouthsb_AR11.xls
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 12 of 24
Data Coverage
Release Area W11-15 has a good coverage of 2D seismic data with between
1 km to 5 km line spacing, comprising surveys of different vintages from the
1970s to the early 1990s: Barrow 3 (DW) 324 (1971), Barrow 4 (DW) 352
(1972), Hilda (1973), X78A (1978), Ningaloo Round 1 (1979), Cape (1980),
Vlaming Head (1980), Vlaming 2D (1992) and GPCT93 (NEPS 2D) (1993).
The area is also intersected by some regional seismic lines acquired by
Geoscience Australia: BMR 17 (1972) and AGSO 110–Barrow/Dampier
(1992) surveys, examples of which are shown in (Figure 5a.)
Most of the Release Area is covered by high quality 3D seismic of the
Carnarvon HCA04A survey acquired in 2005 by BHP Billiton Petroleum Ptd
Ltd and with the PGS Ramford Vanguard vessel.
In 2007, PGS acquired the New Dawn Survey, a multi-client 2D seismic
survey (PGS DATA LIBRARY, 2007) that provides long offset 2D data in deep
water along the North West Shelf of Australia, close to the Release Area.
Gravity and magnetic data were acquired in conjunction with the 2D seismic
(PGS Data library, 2007).
To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-andpromotion/2011.html#data-packages
The North West Shelf Digital Atlas (NWSDA) also covers the Release Area
and provides a regional understanding on a continental scale and delivers a
detailed insight into NWS petroleum provinces (PGS Data library, 2010). This
package also contains regional grids for bathymetry, gravity, magnetic, TOC,
HI and VR data.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 13 of 24
PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Table 1: Petroleum Systems Elements Summary
Sources

Jurassic Dingo Claystone – source of oil in fields in the
sub-basin

Triassic Mungaroo Formation – deltaic sediments are a
source of gas

Mardie Greensand Member

Cretaceous Barrow Group, Zeepaard and Birdrong
Sandstones

Jurassic Dupuy Formation

Triassic sandstones

Cretaceous Muderong Shale (regional seal)

Intraformational seals within the Upper Triassic and
Lower Cretaceous deltaic sequences

Cretaceous inversion anticlines and
structural/stratigraphic traps
Jurassic complex structural/stratigraphic channel trap
beneath Late Berriasian anticline
Triassic fault blocks and associated drape
Reservoirs
Seals
Play Types


Petroleum Systems
Two petroleum systems are prospective in the Release Area. The extensive
Locker/Mungaroo–Mungaroo/Barrow petroleum system, which has sourced
some of the giant gas fields in the Northern Carnarvon Basin, was proven
south the Release Area with the discovery of gas in the Mungaroo Formation
at Falcone 1A.
The Triassic sedimentary succession in the Release Area has proven
potential for mature source facies, including possible organic-rich units in the
Lower Triassic (marine Locker Shale equivalents) and Upper Triassic (deltaic
Mungaroo Formation facies and marine equivalents). The Upper Jurassic
Dingo Claystone is the principal source for oil in the Exmouth Sub-basin
(Tindale et al, 1998). This unit is relatively thick within the Release Area W1115.
Accumulations of the productive Dingo–Barrow petroleum system of the
Exmouth Sub-basin lie only 25 km southwest to the Release Area and even
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 14 of 24
closer in the Griffin field, in the adjacent Barrow Sub-basin. Migration of
hydrocarbons from the Upper Jurassic source kitchens in the central Exmouth
Sub-basin was focused towards the Release Area during the Early
Cretaceous (Tindale et al, 1998; Smith et al, 2003).
Source Rocks
Potential source intervals in the Exmouth Sub-basin occur in the fine grained,
deepwater and pro-delta facies deposited in the Late Jurassic and Early
Cretaceous. Some hydrocarbon generation from the gas-prone Mungaroo
Formation system and older Triassic source rocks presumably occurred in the
Exmouth Sub-basin during the Jurassic.
The Lower Barrow Group and Dingo Claystone have good oil source
potential. The synrift anoxic marine shales of the Late Jurassic Dingo
Claystone are the principal effective source for oil in the Dampier, Barrow and
Exmouth Sub-basin (Tindale et al, 1998; Longley et al, 2002). Modelling
suggests that although the Dingo Claystone is capable of generating both oil
and gas, the majority of the gas is likely the result of biodegradation of
trapped oil (biogenic methane). The Mungaroo Formation equivalent could
source both gas and oil.
Reservoirs
Proven reservoirs in the Exmouth Sub-basin are listed in Link to Table 1 and
potentially extend into Release Area W11-15.
Good reservoirs were encountered in the Late Triassic Mungaroo Formation
equivalent at Zeepaard 1 (Esso Australia Ltd, 1981; Figure 4). Two gas sands
were interpreted in the Mungaroo Formation equivalent from electric logs, with
average porosity of 14.5% and 10.6%, respectively. The Mungaroo Formation
is interpreted to consist of low-sinuosity river, levee bank and overbank
deposits in Zeepaard 1 (Esso Australia Ltd, 1981). Several point-bar deposits
and a 57 m thick stream sequence with some good quality reservoirs were
intersected in Resolution 1(Esso Australia Ltd, 1980). However, porosity
reduction due to siderite, calcite and pyrite cements and abundant kaolinitic
clay matrix is frequently observed in these sandstones. The Triassic reservoir
is probably too deep across most of the Release Area W11-15 to be a good
reservoir (Figure 5b)
The Upper Jurassic Dupuy Formation was recognised as a reservoir within
the Eskdale structure (Figure 4). It has a reservoir quality and sediment
accumulation strongly influenced by fluvial discharge. The Eskdale Member
(Dupuy Formation) is a 36.9 m thick gas- and oil-bearing sandstone
succession at Eskdale 2 with an average porosity of 27.8% and an average
clay content of 7.2%. It is composed of a fine-grained subarkose with mainly
quartz, K-feldspar, unaltered/chloritised faecal pellets and argillaceous
intraclasts. Similar reservoirs may exist in the northwestern part of the
Release Area, close to the Resolution Arch structure.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 15 of 24
The Early Cretaceous Barrow Group equivalent (Macedon Member, Pyrenees
Member, Barrow Group sandstones) host significant hydrocarbon
accumulations throughout the Exmouth Sub-basin and extend into the
Release Area (Figure 4).
The Macedon Member sandstone is interpreted to have been deposited as
turbidites or mass flow deposits and has very good reservoir properties, with a
net:gross ratio of 81% and the net sands having an average porosity of
26.7%. It hosts a gross 21.9 m oil column at Enfield 1 (Woodside, 1999).
However, the 13.1 m gross (13 m net) Macedon Member sandstone of
excellent reservoir quality is water saturated at Eskdale 2 (BHP Billiton, 2005).
The shallow marine, uppermost Tithonian to lower Berriasian Pyrenees
Member of the Barrow Group was intersected in Crosby 1 (BHP Billiton, 2004)
and the pay interval has an average porosity of 29.3% with an average water
saturation of 21.2%.
The Pyrenees Member sandstones are good reservoirs throughout the
interval at West Muiron 5 with a gas-bearing layer, with a net:gross ratio of
91%, a high average porosity of 29% and an average water saturation of
15%, overlying an oil bearing layer with net:gross of 70%, a high average
porosity of 25% and an average water saturation of 45% (BHP Petroleum,
1994b). The Pyrenees Member sandstones at Crosby 1 are clean and
variably argillaceous/sideritic quartzarenites and subarkoses grading to
argillaceous, subarkosic sandstones with increasing depth. Most sands have
been little affected by diagenesis and are consequently unconsolidated with
well preserved intergranular porosity and good permeability (BHP Billiton,
2004).
The Altair Sand is unique among the Barrow Group sands encountered in
Altair 1 well and extends into the northern portion of the Release Area. These
sands have good reservoir properties with significantly higher porosity than
the Barrow Group sands above and below (25% compared to 13% and 18%),
a property due to the near absence of quartz overgrowth cement (West
Australian Petroleum Pty Ltd, 1995). This sand contains formation water less
saline than the water occurring in the Barrow Group sands above and below
and is significantly isolated, preventing equilibration of pore fluids with those in
surrounding sands (West Australian Petroleum Pty Ltd, 1995).
The Barrow Group sandstones are good reservoirs, composed predominantly
of quartz grains, weakly cemented by siderite and pyrite, with a small amount
of clay matrix and log-derived porosities in the 20-26% range (Esso Australia
Ltd, 1980). In Coniston 1 (BHP Petroleum Pty Ltd, 2001) the Barrow Group is
a massive quartz sandstone 88 m thick with excellent reservoir quality, with
average porosities of 27% and permeabilities calculated at 4,565 mD and
measured in core at 3,547 mD.
Overlying the Zeepaard and Birdrong formations are good quality reservoir
sands with a high net:gross ratio (Figure 4). These reservoirs were
encountered in York 1 well, located northeast of the Release Area, however
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 16 of 24
they are 100% water saturated at this location (BHP Petroleum Pty Ltd,
1994c).
The overlying Mardie Greensand Member, commonly a hydrocarbon thief
zone, hosts a gas and oil column at Enfield 1 (Figure 4). This unit is also an
excellent reservoir, with a net:gross ratio of 80.4% and the net sands having
an average porosity of 29.5% (Woodside, 1999). It is composed of thin,
moderately hard, glauconitic sandstone, dark green to medium grey, with
poorly sorted, very fine to coarse grains (up to 85% glauconite with 30% clay,
10% silt and traces of pyrite). Only 1.6 m of Mardie Greensand Member is
recognised in Coniston 1 where it is composed of moderately silica-cemented
silty claystones and glauconitic sandstones (BHP Petroleum Pty Ltd, 2001).
This reservoir unit at Resolution 1 is composed of friable glauconitic
sandstone.
Seals
Both regional and intraformational seals are present in the Release Area. The
Lower Cretaceous Muderong Shale is the regional seal across the Exmouth
Sub-basin (Figure 4). Interbedded claystones within the deltaic sequences of
the Triassic Mungaroo Formation, the Dingo Claystone and delta front
siltstones of the Lower Cretaceous Barrow Group (Macedon Mudstone) have
the potential to form intra-formational seals. The Eskdale discovery proves the
viability of lateral pinch-out seals for the Tithonian canyon plays in the subbasin. The Lower Gearle Formation can also provide a seal (West Muiron 3).
Generation and Expulsion
The complex history of hydrocarbon charge in the Exmouth Sub-basin has
been discussed by Tindale et al (1998) and Smith et al (2003).
Some hydrocarbon generation from the gas-prone Mungaroo Formation
system and older Triassic source rocks presumably occurred in the Exmouth
Sub-basin during the Jurassic with the deposition of kilometres of Dingo
Claystone and other sediments in the main depocentre. In the Early
Cretaceous, generation from the Triassic source rocks may have extended
across the sub-basin and onto parts of the Exmouth Plateau. Burial by the
Barrow delta sediments, possibly coupled with elevated heatflow related to
continental breakup, may have been sufficient to push suitable source rocks
into the gas and oil generation window.
Generation and expulsion from the Upper Jurassic Dingo Claystone oil source
rocks commenced in the Early Cretaceous in response to loading by the
Barrow delta system. Modelling suggests that the initial hydrocarbon charge
from the southern and central Exmouth Sub-basin occurred as early as Late
Tithonian and Berriasian, prior to the deposition of the regional Muderong
Shale seal. The modelled peak expulsion occurs prior to the interpreted Late
Berriasian faulting episode. Stratigraphic trap formation is interpreted to have
occurred prior to peak expulsion, with the Late Berriasian faulting providing
post-charge re-configuration and possible conduits for additional hydrocarbon
charge (or leakage). The presence of hydrocarbons in the primary objective in
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 17 of 24
Eskdale 2 indicated that the prospect had access to a potentially significant
volume of mature hydrocarbons. MDT fluids from the Eskdale 1 residual zone
appeared not to be biodegraded. Traps reliant on Muderong seals may have
been charged from the northern part of the sub-basin where generation
occurred from the Hauterivian to mid-Cretaceous. Campanian inversion
(growth of the Novara Arch) and uplift terminated hydrocarbon generation
from the Jurassic source “kitchen” (Smith et al, 2003), re-ordered migration
pathways, formed new traps and kept oil reservoirs shallow and cool,
maximising the risk of biodegradation. The progradation of the Miocene to
Holocene carbonate wedge over the eastern part of the Exmouth Sub-basin
has produced a late gas charge which has mixed with biogenic gas in
accumulations located to the east of the Release Area.
Play Types
The Seismic line 110/12 on Figure 5b illustrates proven and potential
petroleum plays within the Release Area.
The proven traditional Triassic fault block play (Figure 5b, play type 1), which
hosts most of the hydrocarbon reserves in the Northern Carnarvon Basin, is
adjacent to the Release Area, to the west and east. Mungaroo Formation
sandstones in fault block traps are sealed by either the Dingo Claystone or
intraformational seals. Gas sands interpreted in the Mungaroo Formation
equivalent from electric logs at Zeepaard 1, north of the Release Area W1115, is an example of this play type.
Confined (Eskdale) and partially confined channels have been proven to
contain hydrocarbons within the Jurassic sandstones plays (Figure 5b, play
type 3). The Eskdale 2 trap is a complex structural/stratigraphic channel trap
beneath the collapsed core of the north-northeast-oriented late Berriasian
Resolution Arch. Similar traps with Jurassic sandstones may exist within the
Release Area.
Complex combination structural-stratigraphic trap within the Lower Barrow
Group represent the major producing traps for the oil province within the subbasin (Figure 5b, play type 4). A similar prospect is interpreted within the
Release Area, in the lower Barrow Group sandstone oil play, sourced from the
Dingo Claystones, sealed by Muderong Shale or inter-bedded claystones.
The Tomcat prospect, located in the central and southern part of the Release
Area, was formerly known as Ponsonby has been reassessed by Octanex
and presented in the RPS report (Octanex, 2009). The reassessment
suggests that, due to its depth of burial, the Tomcat Prospect is likely to be a
gas and possibly condensate play. It was identified from a group of seismic
amplitude anomalies, which are interpreted to represent hydrocarbon-bearing,
Cretaceous, deep-water channel and fan sandstones. The prospect has been
mapped using data from a high quality 3D seismic survey acquired during the
HCA04 3D seismic survey. This mapping identified and mapped two seismic
reflectors at the level of the anomalies. Depth structure mapping at these
levels shows these horizons generally plunge towards the north-east with no
independent structural closures. The extent of the prospect is defined by
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 18 of 24
seismic amplitude anomalies at and below these mapped horizons. The two
target levels are separated by a thin stratigraphic interval interpreted from
seismic to be shale (Octanex, 2009).
Trapping potential is also confirmed by the presence of a hydrocarbon column
within the Mardie Greensand Member (Enfield 1) which may also exist within
the Release Area (Figure 5b, play type 5).
Play types based on Lower Cenozoic sands have proven to be viable
elsewhere in the adjacent Barrow Sub-basin (Maitland field; Figure 5b, play
type 6).
Critical Risks
For the Mungaroo Formation play, charge and reservoir quality are the main
risks. The gas charge is considered to be locally derived from the underlying
Triassic sequence. Diminished reservoir qualities due to diagenetic
overprinting are another risk. However, the application of amplitude analysis
with 3D seismic coverage can image gas within reservoirs and improve
success rates. The depth to the Triassic across much of the Release Area
limits this play type.
Risk for the Jurassic play (where sand is found within the shale-prone
sequence) is suggested to be related to capillary breach or burial and both
could have led to the residual column in Eskdale 1 (BHP Billiton, 2005).
The greatest risks for the Barrow Group plays are believed to be associated
with the effectiveness of the seal and to a lesser extent the reservoir
effectiveness. In the Tomcat prospect, the degree of connection between the
sand bodies within unconfined fan deposits at the end of a channel feeder
system and the sealing capacity of potential seal sediments contribute to a
high seal risk. Assuming the seals are present, the ability of the seal to retain
large columns of gas is still a risk. For these sandstones, their depth of burial
is such that reservoir quality may have been reduced due to diagenetic
processes. The GPoS (Geological Probability of Success) of the Tomcat
prospect falls within the high risk category (Octanex, 2009). Risks for this play
that have been identified in the wider Exmouth Sub-basin also apply, including
hydrocarbon charge, with migration required from the north of the Release
Area, and biodegradation of an early oil charge. Smith et al (2003) noted that
these risks can be mitigated by high quality reservoirs that allow viscous oil to
flow, and that less biodegraded oil will be hosted in the deeper and hotter
reservoirs, beneath seals other than those of the Muderong Shale.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 19 of 24
FIGURES
Figure 1:
Location map of Release Area W11-15 in the Exmouth Subbasin, Northern Carnarvon Basin.
Figure 2:
Graticular block map and graticular block listings for Release
Area W11-15, in the Exmouth Sub-basin, Northern Carnarvon
Basin.
Figure 3:
Structural elements of the Exmouth Sub-basin over a residual
Bouguer gravity map (from Morse, 2010), and showing Release
Area W11-15, key discoveries and location of seismic section
110/12 shown on Figure 5a.
Figure 4:
Generalised stratigraphy of the Exmouth Sub-basin based on
the Northern Carnarvon Basin Biozonation and Stratigraphy
Chart (Nicoll et al, 2010). Geologic Time Scale after Gradstein
et al (2004) and Ogg et al (2008). Major accumulations are
shown.
Figure 5a:
AGSO seismic line 110/12 across the Exmouth Plateau and
Exmouth Sub-basin. Wells, Release Area and inset location for
Northern Carnarvon Basin EXMOUTH Sub-basin RELEASE
AREA Figure 5b are indicated. Location of the line is shown on
(Figure 3).
Figure 5b:
Enlargement of AGSO seismic line 110/12 showing conceptual
petroleum plays across the northern Exmouth Sub-basin and in
the Release Area.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 20 of 24
REFERENCES
APACHE ENERGY, 2008—Beg-1, WA-357-P, Well Completion Report, Basic
Data, issued November 2008.
ARTICLES HUB, 2010—[Web page] Aarkstore Enterprise - Stybarrow
Project, Australia, Commercial Asset Valuation and Forecast to 2016
http://www.articleshub.org/article/18565/Aarkstore-Enterprise---StybarrowProject,-Australia,-Commercial-Asset-Valuation-and-Forecast-to-2016.html
(last accessed 25 October 2010)
ARDITTO, P.A., 1993—Depositional sequence model for the post-Barrow
Group Neocomian succession, Barrow and Exmouth Sub-basins, Western
Australia. The APEA Journal, 33 (1), 152–160.
BAILEY, W.R., UNDERSCHULTZ, J., DEWHURST, D.N., KOVACK, G.,
MILDREN, S. AND RAVEN, M., 2006—Multi-disciplinary approach to fault
and top seal appraisal; Pyrenees–Macedon oil and gas fields, Exmouth Subbasin, Australian Northwest Shelf. Marine and Petroleum Geology, 23, 241–
259.
BARBER, P., 1988—The Exmouth Plateau deepwater frontier: a case study.
In: Purcell, P.G. and Purcell, R.R. (editors), The North West Shelf, Australia:
Proceedings of the Petroleum Exploration Society of Australia Symposium,
Perth, 173–187.
BHP BILLITON, 2004—Crosby-1, WA-12-R, Well Completion Report,
Interpretive volume, June 2004.
BHP BILLITON, 2005—Eskdale-2 & Eskdale-2/CH1, WA-255-P(2), Well
Completion Report, Interpretive volume, March 2005.
BHP BILLITON, 2010—[Web page] BHP Billiton Approves Macedon Gas
Development In Western Australia, 24 Sep,
http://www.bhpbilliton.com/bb/investorsMedia/news/2010/bhpBillitonApproves
MacedonGasDevelopmentInWesternAustralia.jsp (last accessed 25 October
2010)
BHP PETROLEUM PTY LTD, 1994a—West Muiron 3, WA-155-P, Well
Completion Report, Interpretive volume, March 1994.
BHP PETROLEUM PTY LTD, 1994b—West Muiron 5, WA-155-P, Well
Completion Report, Interpretive data, September 1994.
BHP PETROLEUM PTY LTD, 1994c—York 1, WA-210-P, Well Completion
Report, Interpretation, June 1994.
BHP PETROLEUM PTY LTD, 2001—Coniston 1, Well Completion Report,
Interpretative Volume, February 2001.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 21 of 24
BRADSHAW, M.T., FOSTER, C.B., FELLOWS, M.E. AND ROWLAND, D.C.,
1999—The Australian search for petroleum–patterns of discovery. The
APPEA Journal, 39 (1), 1–18.
BUSSELL, M.R., JABLONSKI, D., ENMAN, T., WILSON, M.J. AND BINT,
A.N., 2001—Deepwater exploration: northern Western Australia compared
with Gulf of Mexico and Mauritania. The APPEA Journal 41(1), 289–319.
DEPARTMENT OF MINES AND PETROLEUM, 2008——[Web page]
PETROLEUM IN WESTERN AUSTRALIA
http://www.dmp.wa.gov.au/documents/Petroleum_in_WA_April_2008.pdf (last
accessed 25 October 2010)
DEPARTMENT OF MINES AND PETROLEUM, 2010——[Web page]
PETROLEUM IN WESTERN AUSTRALIA
http://www.dmp.wa.gov.au/documents/Petroleum_in_WA_magazine_09_10.p
df (last accessed 25 October 2010)
ELLIS, G.K. AND JONASSON, K.E., 2002—Rough Range Oil Field,
Carnarvon Basin. In: Keep, M. and Moss, S.J. (eds), The Sedimentary Basins
of Western Australia 3: Proceedings of the Petroleum Exploration Society of
Australia Symposium, Perth, 707–718.
ESSO AUSTRALIA LIMITED, 1980—Resolution 1, Well Completion Report.
ESSO AUSTRALIA LIMITED, 1981—Zeepaard 1 Well Completion Report,
unpublished.
GASCOYNE DEVELOPMENT COMMISSION OFFICES, 2010——[Web
page] Gascoyne Mining Investment Profile
http://www.gdc.wa.gov.au/uploads/files/MINING%20profile%20sheet%20WEB
.pdf (last accessed 25 October 2010)
GRADSTEIN, F., OGG, J. AND SMITH, A., 2004—A Geologic Time Scale
2004. Cambridge: Cambridge University Press, 589.HOCKING, R.M., 1990—
Carnarvon Basin. In: Geology and Mineral Resources of Western Australia.
Western Australia Geological Survey, Memoir 3, 457–495.
HOCKING, R.M., 1990—Carnarvon Basin. In: Geology and Mineral
Resources of Western Australia. Western Australia Geological Survey,
Memoir 3, 457–495.
JABLONSKI, D., 1997—Recent advances in the sequence stratigraphy of the
Triassic to Lower Cretaceous succession in the Northern Carnarvon Basin,
Australia. The APPEA Journal 37 (1), 429–454.
LONGLEY, I.M., BUESSENSCHUETT, C., CLYDSDALE, L., CUBITT, C.J.,
DAVIS, R.C., JOHNSON, M.K., MARSHALL, N.M., MURRAY, A.P.,
SOMERVILLE, R., SPRY, T.B. AND THOMPSON, N.B., 2002—The North
West Shelf of Australia – a Woodside perspective. In: Keep, M. and Moss,
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 22 of 24
S.J. (editors), The Sedimentary Basins of Western Australia 3: Proceedings of
the Petroleum Exploration Society of Australia Symposium, Perth, 27–88.
MALEK, R., 2006—Western Australia’s developing hydrocarbon potential. In
Australia in Focus, PESA News October/November 2006. Petroleum
Exploration Society of Australia, 6–9.
MITCHELMORE, L. AND SMITH, N.H., 1994—West Murion discovery, WA155-P—new life for an old prospect, In: Purcell, P.G. and Purcell, R.R.
(editors), The Sedimentary Basins of Western Australia: Proceedings of the
Petroleum Exploration Society of Australia Symposium, Perth, 584–596.
MORSE, M., 2010—Potential field methods prove effective for continental
margin studies, AusGeo News, June 2010, Issue 98— [Web page]
http://www.ga.gov.au/ausgeonews/ausgeonews201006/geology.jsp (last
accessed 25 October 2010)
NICOLL R.S, G. BERNADEL, T. HASHIMOTO, A.T. JONES, A.P. KELMAN,
J.M. KENNARD, S. LE POIDEVIN, D.J. MANTLE, N. ROLLET AND P.R.
TEMPLE (2010) Northern Carnarvon Basin, Biozonation and Biostratigraphy,
2010, Chart 36. On CD: Basin Biozonation and Stratigraphy Charts, 2010.
Geoscience Australia.
NORVICK, M.S., 2002—Palaeogeographic Maps of the Northern Margins of
the Australian Plate: Final Report. Unpublished report for Geoscience
Australia.
OCTANEX, 2009—[Web page] Sep 22 2009,
http://www.nsxa.com.au/ftp/news/021721940.PDF (last accessed 25 October
2010)
OGG, J. G., OGG, G. AND GRADSTEIN, F. M., 2008—The Concise Geologic
Time Scale. Cambridge: Cambridge University Press, 177.
OIL&GAS JOURNAL, 2010—[Web page] Sep 24 2010, Development set for
gas field off Australia http://www.ogj.com/index/articledisplay/7126982870/articles/oil-gas-journal/exploration-development2/2010/09/developmentset_for/QP129867/cmpid=EnlEDSeptember302010.html (last accessed 25
October 2010)
PGS DATA LIBRARY, 2007—[Web page] New Dawn 2D seismic survey
2007, http://www.pgs.com/Data_Library/Asia-Pacific/Australia/New-Dawn-2D
(last accessed 25 October 2010)
PGS DATA LIBRARY, 2010—[Web page] North West Shelf Digital Atlas,
http://www.pgs.com/Data_Library/Asia-Pacific/Australia/North-West-ShelfDigital-Atlas/ (last accessed 25 October 2010)
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 23 of 24
POLOMKA, S.M., BRUINS, J., SPANNINGA, G.A. AND MENNIE, J.P.,
1999—WA-271-P, Exmouth Sub-basin – integrated prospectivity evaluation.
The APPEA Journal 39 (1), 115–127.
SCIBIORSKI, J.P., MICENKO, M. AND LOCKHART, D., 2005—Recent
discoveries in the Pyrenees Member, Exmouth Sub-basin: a new oil play
fairway. The APPEA Journal 45 (1), 233–251.
SMITH, N., DEMPSEY, C., JACKSON, M., AND PRESTON, J., 2003—
Overcoming historical bias: an integrated geological and engineering
assessment of the Coniston prospect, Exmouth Sub-basin. The APPEA
Journal 43(1), 363–383.
TINDALE, K., NEWELL, N., KEALL, J. AND SMITH, N., 1998—Structural
evolution and charge history of the Exmouth Sub-basin, Northern Carnarvon
Basin, Western Australia. In: Purcell, P.G. and Purcell, R.R.(editors), The
Sedimentary Basins of Western Australia 2: Proceedings of the Petroleum
Exploration Society of Australia Symposium, Perth, 447–472.
VEEVERS, J.J., 1988—Morphotectonics of Australia’s Northwestern Margin—
A Review. In: Purcell, P.G., Purcell, R.R. (Eds.), The North West Shelf
Australia: Proceedings of Petroleum Exploration Society of Australia
Symposium, Perth, pp. 19–28.
WALKER, T.R., 2007—Deepwater and frontier exploration in Australia –
historical perspectives, present environment and likely future trends. The
APPEA Journal 47(1), 15–38.
WEST AUSTRALIAN PETROLEUM PTY LTD, 1995—Altair 1, WA-213-P,
Carnarvon Basin, Well Completion Report, Interpretive volume, September
1995.
WOODSIDE, 1999—Enfield-1, WA-271-P, Well Completion Report,
Interpretive data, November 1999.
Front page image courtesy of Petroleum Geo-Services.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Area QQ11-15, Exmouth Sub-basin, Carnarvon Basin, State
Release Area Geology
Page 24 of 24