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 850–4,500m

·  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 toW12-14 are located in deep to ultra deep water approximately 150 to 500km off the coast of Western Australia on the Exmouth Plateau, within the Northern Carnarvon Basin (Figure1). The Release Areas are located to the west and southwest of the giant (~8Tcf) Scarborough gas field. The Release Areas do not contain any wells and water depths range from about 850 to 4,500m.

Release Area W12-10 is the largest area and consists of 195 graticular blocks covering 15,740km2. Release Area W12-11 consists of 31 graticular blocks with a total area of 2,500km2, while W12-12 comprises 22 graticular blocks covering 1,770km2, W12-13 comprises 21 graticular blocks with an area of 1,685km2 and W12-14 consists of 46 graticular blocks with a total area of 3,675km2.

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 Figure2.

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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 (Figure3). Most of the plateau is underlain by 10 to 15km of generally flat-lying and tilted, block-faulted Lower Cretaceous, Jurassic, Triassic and older sedimentary rocks (Figure4). 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 (Figure3)

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 (Figure4). 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 (Figure5) 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 Investigator1 and Zeepaard1 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.

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), mid-outer 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 (740–1,375m) wells were drilled (Walker, 2007), targeting oil charge from the Jurassic Dingo Claystone. Two wells were gas discoveries: Jupiter1, a Triassic horst trap; and Scarborough1, an inverted Lower Cretaceous Barrow Group basin floor fan. At the time of the Scarborough1 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 Jansz1 in 2000 and its lateral extent realised with the drilling of Io1 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 Thebe1 in Permit WA-346-P and discovered 2–3Tcf (57–85Bcm) of gas (BHP Billiton, 2007; Anonymous, 2007). Thebe2 (2008) was drilled 16km 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 16well drilling commitment. Thirteen of the 16 wells were gas discoveries including Glencoe1, Briseis1, Nimblefoot1, Lightfinger1, Rimfire1, Mentorc1, Hijinx1 and Glenloth1. In the Glencoe1, Briseis1 and Nimblefoot1 discoveries, accumulations occur within the post-Callovian section, with Briseis1 also encountering additional pay in the Triassic Mungaroo Formation (Smallwood et al, 2010). The Oxfordian (W. spectabilis) sandstones encountered in Glencoe1 are analogous to those encountered at Io/Jansz. In contrast, Nimblefoot1 and Briseis1 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).

Other recent gas finds have been made at Achilles1 (2009), Satyr1 (2009) and Sappho1 (2010) to the east; Martell1 (2009), Yellowglen1 (2009), Noblige1 (2010), Larsen1 (2010), Larsen Deep1 (2010), Remy1 (2010) and Martin1 (2011) to the northeast; and Kentish Knock1 (2009), Guardian1 (2009), Brederode1 (2010) and Alaric1 (2010) on the western Exmouth Plateau (Figure1). The discovery of gas at Brederode1 (Chevron permit WA-264-P) and Alaric1 (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 (Vos1 in permit WA-439-P; Jonasson, 2011) and Woodside (Cadwallon1 and Genseric1 in permit WA-434-P; Woodside, 2011).

Well control

Investigator1 (1979)

Investigator1 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 (Figure6; Esso Australia Ltd, 1980a). The well was drilled in 841m water depth and reached a TD of 3,745mKB. It penetrated and sampled an Albian to Barremian succession of claystone, marl and siltstone to 1,492mKB, overlying a 1,748m 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 15m section of Upper Jurassic claystone, Middle to Lower Jurassic marl (44m), Upper Triassic (Rhaetian) marl (65m) and Upper Triassic (Norian) interbedded sandstone, siltstone, claystone and minor coal of the Mungaroo Formation (382m 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 48-86% 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.

Jupiter1 (1979)

Jupiter1 was drilled by Phillips Australian Oil Company in water depths of 960m to test a tilted Triassic horst block. The well reached a TD of 4,946mRT 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 466m of inferred calcareous ooze and marl of Holocene to Late Cretaceous age without returns, and sampled Cretaceous chalk, calcareous claystone and siltstone to 1,857mRT, and a 15m section of Upper Jurassic claystone to 1,872mRT. This Jurassic claystone was unconformably underlain by 23m of Upper Triassic (Rhaetian) carbonate and claystone, 39m 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 (1,895–4,946mRT). This is the maximum drilled thickness of Triassic section on the Exmouth Plateau.

A 22.5m gas column was discovered in Upper Triassic sandstones (1,911–1,933mRT; Brigadier Formation) with reserves of about 0.15Tcf (4Bcm; 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).

Scarborough1 (1979)

Scarborough1 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 912m and was abandoned at a TD of 2,364mKB 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 683m thick). Drilling was abandoned within the Barrow Group, and the underlying Triassic section was not reached.

Scarborough 1 discovered a 59m gas column within good quality sands (average 23% porosity) of the lower Barrow Group basin floor fan sealed by prodelta claystone. Formation testing at 1,904.5mKB recovered 5.2m3 of methane with only 0.12% ethane and no fractions heavier than propane.

Several appraisal wells have been drilled; Scarborough2 (1996) and Scarborough3,4 and5 (2004–2005). Scarborough2 was drilled to a TD of 2,068mKB 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 84m 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 39m gross gas interval with lower than expected porosity (20%), permeability (<1-0mD) and gas saturation (49%). The lower fan reservoir contained a 28m gross gas interval with excellent porosity (26%), permeability (1,000–5,000mD) 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 Scarborough1.

Scarborough3 was located on the southwest flank of the structure to appraise the upper fan complex of the Barrow Group. It encountered a 53m gross gas column and demonstrated that high-quality, amalgamated turbidite sands were developed in the upper fan (Gorter, 2005).