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The North West Shelf of Australia - A Woodside Perspective*
By
I.M.
Longley, C. Buessenschuett, L. Clydsdale, C.J. Cubitt, R.C. Davis, M.K.
Johnson, N.M. Marshall, A.P. Murray, R. Somerville,
T.B. Spry, and N.B. Thompson
Search and Discovery article #10041 (2003)
Woodside Energy Ltd, 1 Adelaide Tce, Perth, WA 6000 ([email protected])
*On line version of article of the same title by the same authors published in The Sedimentary Basins of Western Australia 3, M. Keep and S.J. Moss, eds., as Proceedings of the Petroleum Exploration Society of Australia Symposium, Perth WA. Appreciation is expressed to the Petroleum Exploration Society of Australia for permission to present this article online.
The North West Shelf of Australia is a world class gas province with minor oily sweet spots. It is a marginal rift with pre-rift Permo-Triassic intracratonic sediments, overlain by Jurassic to Cainozoic syn- and post-rift successions. These were deposited in response to rifting and seafloor spreading of at least three continental blocks in Oxfordian, Tithonian and Valanginian times. Rifting was initiated in the central Argo area in the Oxfordian. In Tithonian times, the rifting jumped to the north of Timor (where the spreading record has been subsequently subducted), then in the Valanginian it moved to the southern Cuvier area. This break-up history produced a complex spatial and temporal distribution of rift and post rift deposits, which strongly control the efficiency and liquid hydrocarbon potential of the margin’s petroleum systems.
Since exploration drilling
commenced in 1953, some 754 exploration wells have been drilled (at Dec 2001),
discovering estimated reserves of 2.6 billion bbls of 
oil
, 2.6 billion bbls of
condensate and 152 Tcf of gas within 233 hydrocarbon fields. Most of the
successful traps comprise sands within rift-related horsts and tilt blocks, or
sands within overlying drape structures. Almost all (97%) of the margin’s
resources are reservoired beneath the (dominantly Cretaceous) regional seal.
Other more complex traps have been rarely successful, in general the margin
offers little encouragement for stratigraphic entrapment due to the sandy
section beneath (and above) the regional seal.
The dominance of gas (84% by
boe) is due to the quality, and often the high maturity, of the source rocks
within all identified hydrocarbon systems. Rare oil-prone source rocks are
present, but their effectiveness in producing economic oil fields relies on
protection from gas flushing, and/or biodegradation or the selective loss or
separation of the dominant gas charge via fault leakage or water washing.
Effective oil source rocks are found locally within mainly Jurassic pre- and syn-rift
deltaic, or syn-rift marine settings, within partially restricted depositional
settings, whereas sediments deposited in open marine environments are typically
lean and gas-prone.
The extensive coverage of 3D seismic acquired in the late 1990s over the ‘oily’ portions of the margin has not resulted in large exploration successes. This is due to the simple effective traps at base regional seal level being beneath the amplitude floor and had been previously identified with 2D data. Small traps were identified by 3D in these areas, and these discoveries will be developed as infrastructure matures, and economic thresholds decrease.
Some 119 Tcf of gas reserves remain undeveloped, together with an estimated 1400 mmbbls of potential condensate reserves. The future of the North West Shelf hydrocarbon province largely lies in developing these resources and exploring for traps surrounding the future infrastructure. The province is still under-explored by global standards, especially outside of proven oily areas, where large potential volumes remain in untested deepwater Mesozoic basins, and inboard poorly explored Palaeozoic basins.
The North West Shelf of
Australia provided the initial growth platform for Woodside, and Woodside will
continue to be committed to further significant exploration in the province.
With vast discovered, but undeveloped, gas reserves, Woodside is focussed on
developing existing gas reserves, whilst continuing exploration for oil.
However, the low probability of discovering a new oily sub-basin, simple trap
geometries, gassy charge and the poor record of 3D seismic in proven oily areas,
creates a challenge to compete for exploration funds for oil exploration on the
North West Shelf when compared against global oil opportunities.
The North West Shelf of
Australia provided the initial growth platform for Woodside, and Woodside will
continue to be committed to further significant exploration in the province.
With vast discovered, but undeveloped, gas reserves, Woodside is focussed on
developing existing gas reserves, whilst continuing exploration for oil.
However, the low probability of discovering a new oily sub-basin, simple trap
geometries, gassy charge and the poor record of 3D seismic in proven oily areas,
creates a challenge to compete for exploration funds for oil exploration on the
North West Shelf when compared against global oil opportunities.
|
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben tPetrel Sub-basin & Bonaparte Inboard Shelf
tDampier, Barrow & Exmouth Sub-basins tSahul, Flamingo & Nancar area tGreater Kelp-Sunrise High and Malita Graben |
{Figure Caption (1)}
The North West Shelf (Figure 1) is a geographic term applied to the offshore and marginal basins areas flanking the northwest coast of Australia (Purcell and Purcell, 1988a).
Woodside was first awarded a
268,580 km2 exploration permit (PE213H) on the North West Shelf in
1963, and by 1965 had equity in a further nine blocks, with a total area of
367,000 km2, which is equivalent to 0.53, 1.5 and 10.8 times the land
area of Texas, UK and Holland respectively. Early exploration success within
these and subsequent permit areas led ultimately (in 1984) to commercial
development. By 2001, Woodside operated an onshore LNG plant with three
processing LNG (liquified natural gas) trains (soon to be expanded to four and
probably five), and other offshore operated facilities (two offshore platforms,
two floating production and storage offtake vessels (FPSOs) and a mobile
offshore production unit (MOPU). These facilities in 2001 cumulatively produced
131 cargoes of LNG (7.75 million tonnes of LNG and 803 tonnes of liquified
petroleum gas (LPG)), an average of 536 terrajoules per day of domestic gas,
95,500 barrels of condensate per day and 254,000 barrels of
In 1998,
Woodside perceived that the potential for material growth of the company
exclusively through further exploration within the North West Shelf (and
Australia) was becoming increasingly difficult, due to its focus on exploring
for large In April 2000, Woodside formed a North West Shelf evaluation team with the specific task of improving it’s regional understanding. The work was completed by January 2001 and some of the results are presented in this technical overview.
The study
confirmed that despite Woodside’s ongoing commitment to Geological Synopsis {Figure (2-21) and Table (1) Captions}
Click to view Figures 12, 13, 14, 15 (Sinemurian-Tithonian palaeography).
Click to view Figures 16 and 17 (Berriasian-Barremian palaeography). Click to view sequence of Figures 8, 13, 14, 15, 16, 17 (Norian to Barremian palaeogeography).
Click to view Figures 11, 18, 19, 20, 21 (isopach maps—Triassic-water bottom).
Table
The published geological evolution and petroleum geology of the North West Shelf is described in the proceedings of three Petroleum Exploration Society of Australia symposia edited by Purcell and Purcell (1988a, 1994, 1998). The following geological synopsis is based on these and other published works, integrated with the results of proprietary studies relating to Woodside’s exploration activities over almost 40 years. The limits of the North West Shelf as defined by this study are shown in Figures 2, 3, and 4, the underlying tectonic elements in Figure 5, and a set of schematic regional cross-sections in Figures 6a and 6b. The North West Shelf is comprised of four basins, namely the Northern Carnarvon, Offshore Canning (or Roebuck), Browse and Bonaparte basins, and one orogenic belt, herein termed the Timor-Banda Orogen. The four basins cumulatively comprise the “Westralian Superbasin” (Yeates et. al., 1987), abbreviated to WASB hereafter. The WASB is filled with a thick late Palaeozoic, Mesozoic, and Cainozoic sedimentary succession relating principally to the fragmentation of Gondwana. The Timor-Banda Orogen is the product of a Neogene collision between the distal edge of the WASB with the Banda Arc, and arc systems flanking the Southeast Asian Sundaland Craton (Figure 5) (Metcalfe, 1999; Keep et. al., 2002). The WASB lies predominantly within Australian territorial waters, and the Timor-Banda Orogen lies exclusively within East Timorese and Indonesian waters (Figure 2). This overlap of political and geologic boundaries has historically tended to mask the common geology between the two regions, and confuse the outboard limit of the North West Shelf (sensu geological province as defined on Figure 2). In contrast, the inboard limit of the North West Shelf is generally well defined by the Proterozoic Australian craton. Flanking Palaeozoic basins on the edge of this craton (Figure 5) were the main provenance for Mesozoic WASB sedimentary sequences. The outboard limit of the North West Shelf comprises oceanic crust in the south, and accreted volcanic arc and accretionary wedge material in the north (Figure 5). The lateral limits of the North West Shelf in the southwest and northeast are arbitrarily defined where post-Palaeozoic sediments thin onto platform areas. The combination of sequence stratigraphic modelling within the constraints of a reliable and detailed biostratigraphic framework has had a considerable impact on the geological understanding of the North West Shelf within Woodside over the last decade. Of particular importance was the publication of the Helby et al. (1987) palynological zonation for the Australian Mesozoic, which provided a reliable and unified standard for correlating strata throughout the region. The currently used sequence stratigraphic model is an extension of that defined by Jablonski (1997) for the Dampier Sub-basin, and is based on the integration of electric log and biostratigraphic data from over 750 well sections which were calibrated against modern seismic data. The major surfaces within this sequence stratigraphic model have been used to define a set of regional picks marking the boundaries of the Woodside play intervals shown as Figure 7. The usage of the play intervals avoids the complications of trying to unify the different lithostratigraphic schemes currently being used in the individual basins and sub-basins. The intervals defined by the play intervals are essentially time-related packages of strata bounded by regionally distinct stratigraphic surfaces, and hence are similar to the timeslices applied by AGSO within the region (Bradshaw et al., 1988; AGSO North West Shelf Study Group, 1994). To assist readers familiar with traditional lithostratigraphic nomenclature, the most typical lithostratigraphic unit associated with each play interval is placed in parentheses after the Woodside play names (e.g. J20 (Legendre Formation)). The play names also have an age context, with TR=Triassic, J=Jurassic, K=Cretaceous, and T=Tertiary. Significant tectonic events from within and beyond the study area are illustrated in Figure 7 (after Metcalfe, 1999; Norvick et al., 2001; Norvick and Smith, 2001; Muller et al., 2000; Keep et al., 2002; Hill and Raza, 1999) and the significant Jurassic and Early Cretaceous seismic events and intervening play intervals are summarised in Table 1. The early Palaeozoic Cambro-Ordovician section is not described here, since this section is either deeply buried or absent, and has not materially contributed to the petroleum prospectivity of the study area. The early Palaeozoic is overlain in parts of the Bonaparte Basin with a thick salt deposit, which has later mobilised and formed salt-cored structures in some areas (see Figure 7 of Bradshaw et al., 1994, for palaeogeographic setting; Smith and Sutherland, 1991; Gunn et al., 1988a). The overlying Devonian to Permian section relates to the first two of three significant periods of Gondwanan terrain dispersion where continental fragments drifted northward and subsequently accreted to the Eurasian craton (Metcalfe, 1999). These sequences (PZ20-50 inclusive; Figure 7) form two synrift and sag cycles, filled with variable marine, deltaic and glacial deposits. It is not possible to image or map these Palaeozoic successions on seismic data over the entire study area, as they are overlain, particularly in basinal areas, by thick Mesozoic deposits. The Palaeozoic basin history, best described by Bradshaw et al. (1994), is pieced together from local areas of the WASB where Palaeozoic horizons can be imaged and mapped. Such regions include the Petrel Sub-basin of the Bonaparte Basin (Figure 2) (Mory, 1988; Colwell and Kennard, 1996), within shelfal areas where the onshore Palaeozoic Canning Basin extends offshore beneath the Offshore Canning Basin and in the inboard shelfal areas of the Northern Carnarvon Basin (e.g. Delfos and Dedman, 1988; and Bentley, 1988). Elsewhere there are occasional windows of information through the thick cover by virtue of deep seismic imaging (e.g. Browse Basin, Struckmeyer et al., 1998). The second of the two main Palaeozoic rift phases occurred in the Late Carboniferous, and is the most important rifting event on the North West Shelf, as it gave rise to the WASB (AGSO NORTH WEST SHELF STUDY GROUP, 1994). It relates to the onset of the Sibamasu block separation (Metcalfe, 1999), and resulted in a thick (approx. 10 km), continuous fill of mainly Permian and Mesozoic sediments (Bradshaw et al. 1988), covering the entire NE-SW striking Westralian Basin area (Figure 4). This contrasts with the earlier successions which are interpreted to be less contiguous, and more influenced by the NW-trending early Palaeozoic structural grain (Figure 5) (Bradshaw et al., 1994). Late Carboniferous to Early Permian synrift fill comprises glacio-fluvial sediments which pass upwards into a thick sag section. The sag section itself comprises two units, marine Permian shelfal and shallow water carbonates and sands, overlain, after a major eustatic lowstand, by a thick succession of shelfal Triassic shales, which thicken and become more distal to the northwest (Nicoll and Foster, 1994) (Figure 7). The third significant period of terrane dispersion from the Gondwanan margin occurred in the Late Triassic to Late Jurassic, associated with the Norian drift of the Lhasa block and the subsequent drift of the West Burma and Woyla blocks into the Late Jurassic (Metcalfe, 1999). The Late Triassic Carnian to Norian succession was deposited following a regionally extensive period of significant tectonism, erosion and uplift along the edges of the craton, known as the “Fitzroy Movement” (Forman and Wales, 1981). Synchronous events (e.g. the Scott Reef-Buffon trend was created and the Bedout High further accentuated), are evident on seismic and well data in the offshore Bonaparte, Browse and Canning basins, suggesting a regional tectonic event. These were related either to breakup events from the Gondwanan margin or, more likely, to docking of continental blocks along the adjacent Irian/Papua New Guinea subduction margin. Regardless of the cause, the hinterland uplift and tectonic events associated with the Fitzroy Movement resulted in the influx of a thick sequence of (TR20) sediment in the Northern Carnarvon Basin, pouring out from the uplifted onshore Canning Basin region (Figure 8). These (predominantly) thick deltaic successions prograded some 500 km from the margin of the Onshore Canning basin, to the Exmouth Plateau, and into the marine embayment of the Wombat - Timor Trough (Nicoll and Foster, 1994). The Lhasa block rifted from the northern Indian Margin during the Norian (Metcalfe, 1999). In the WASB this event is associated with a major flooding surface within the basal section of the Rhaetian, which is mapped as the TRR seismic event (Figures. 7 and 9). Following the drift of the Lhasa block, extension along the Gondwanan margin continued, and the West Burma and Woyla Blocks subsequently drifted from the Australian margin of Gondwana. Metcalfe (1999) is not specific about the exact drift ages of the fragments and herein a more detailed model is proposed to explain the stratigraphic and structural observations from the WASB. This model is consistent with the work of Muller et al. (1998), and is based on preserved magnetic marine anomalies, which suggest that Oxfordian and Valanginian drift events respectively formed the Argo and Cuvier oceanic basins. The interpreted age of block rotation in different areas, from latest Triassic to Early Cretaceous, is shown as Figure 5, while the age of the major rifting events (rift onset and cessation ages) along the margin is shown as Figures 7 and 9. The proposed model to explain these observations is shown as Figure 10, whereby the West Burma Block was comprised of three sub-blocks which rifted during the Sinemurian, Oxfordian and Tithonian, respectively. It is not considered crucial that the blocks fully rifted and drifted from the Gondwanan margin during these periods, since failed rift events may also have resulted in associated flooding events further inboard onto the craton. In the proposed model, West Burma Block 1 (Figure 10) began to rift in the latest Hettangian as inferred from the dating of a major basinward shift of facies at the CTS5 seismic event, which marks the onset of a major phase of sand influx. This extension continued until break-up in the Sinemurian. The subsidence caused by the emplacement of oceanic crust, and the change to drift tectonism is expressed inboard as the major JP1 flooding event (seen over the North Carnarvon to Browse area – Figure 5). This flooding event becomes progressively less distinct in the Bonaparte Basin, as this northern area was beyond the limit of rift block rotation (Figure 5) and remained largely unaffected. The amount of accommodation space created by this event is shown by the thickness of the overlying J20 section (Figure 11a), which comprises a massive succession of deltaic prograding sediments (Figure 12) in the outboard Beagle area (Figure 2). Rifting of the second West Burma Block from the margin (Figure 10) began in the Callovian (JC seismic event) and was complete by the Oxfordian (JO seismic event) (Figures 7 and 9). The palaeogeography of the synrift J30 Callovian section is shown on Figure 13, and highlights the dramatic change in palaeogeography from the underlying broad delta plain in the Bathonian (Figure 12), to deposition within narrow rift valleys. Again, because of the distance of the Bonaparte Basin from the main rift axis, and the area of block rotation (Figure 5), the section in this area remained largely unaffected by the southern rift event, with deposition continuing over a stable broad deltaic plain (Figure 12). Rift related valleys formed during this phase. Based on the log motifs and models presented by Ravnas and Steel (1998) for marine rift systems, these features were initially underfilled but were subsequently infilled by marine shale and sandstone, some of which appear to be shed from the craton during lowstand events. In the Tithonian, it is interpreted that a third West Burma Block separated from the margin, from a position outboard of the Bonaparte Basin and that the oceanic crust and magnetic anomalies recording this event have been subducted (Figure 10). The only direct evidence for this model is the interpreted block rotation observed in the northern Bonaparte wells, and the associated significant unconformity near the base of the Tithonian (JT, top D. swanense Zone) observed in well sections (Pattillo and Nicholls, 1990) (note this reference labelled this event as the Intra-Kimmeridgian event within the D. swanense dinoflagellate zone of Helby et al. (1987), which is now interpreted to be near base Tithonian in age). In the Vulcan, Sahul and Flamingo synclinal areas the onset of this rifting event is interpreted to be marked by the JK intra-Kimmeridgian seismic event, which records the relative deepening and reduction of clastic sediment supply into the already sediment-starved rift basin areas. The rift and associated flood is a precursor to a circum - Ashform Platform oceanic current (see Figure 14) which ended the relative restriction of the Vulcan Sub-basin failed rift arm (which existed prior to the Tithonian rift during J40 time). The basal condensed section which marks the rift onset, flood and change in circulation conditions is a marl unit in the Sahul Syncline (Gorter and Kirk, 1995). Inboard rift shoulder areas were eroded during footwall uplift and subsequent relative lowstand periods and basinal sands were then deposited in the Barrow-Dampier, Vulcan and Nancar sub-basins. The tectonic influence of the Tithonian rifting event on the southern portion of the margin was minimal, as these depocentres were located at some distance from the main active rift area (see Figure 15). In the Berriasian, Greater India began to rift from Gondwana (Figures 7, 9 and 10), with the formation of a long narrow rift basin running down the length of the current Perth Basin. The onset of this rift caused a marine flooding event (K seismic event on Figures 7 and 9) which is observed over the whole margin. It is interpreted that the Perth Basin rift valley then disgorged a massive sedimentary load into the southern Northern Carnarvon Basin ("Barrow delta"; Figure 16). Uplift of hinterland areas inboard of the Browse Basin also produced local progradational deltaic deposits in the Browse area (Figure 16). With the separation of Greater India in the Valanginian (Figures 7, 9 and 10), the entire WASB was subject to regional post-rift sag, and the various underlying sandy environments were drowned by a regional marine flooding (KV seismic event) (Figure 17). In the south, the remnants of the Barrow delta, now cut off from its Perth Basin hinterland, were reworked by transgression, and a small local delta prograded in the offshore Broome area. The isopach between the Oxfordian and Valanginian seismic (see Figure 18) illustrates the combined thicknesses of the Barrow delta and underlying Oxfordian rift basins in the Barrow region, the Oxfordian rift basins in the Dampier Sub-basin, the Oxfordian and Tithonian rift sequences in the Vulcan Sub-basin, and the Tithonian rift basin in the Malita Graben area. What is particularly significant from this figure is the interpreted absence of other rift basins from the remainder of the margin, particularly within the offshore Browse and Canning Basin regions. The thermal sag phase for the WASB following the separation of greater India in the Valanginian can be divided into three broad units; · Early Cretaceous K20/K30 interval (KV - KA seismic events) · Middle to Late Cretaceous K40/K50/K60 interval (KA -T seismic events) · Tertiary T10/T30 interval (T-Water Bottom seismic events). Isopachs for these intervals are shown as Figures 19, 20 and 21, respectively. What is clear from these maps is that isopach thick intervals from the earliest sag unit (K20/K30) (Figure 19) do not overlie the rift basin areas highlighted on Figure 18, as would be expected in a simple rift-drift steershorn model. This is because many areas of the margin were starved of sediment throughout the K20/K30 period, and the basin was underfilled with sediment. This “bathymetric effect” can, and has, led to the misinterpretation of anomalous subsidence curves as explained by Kaiko and Tait (2001). The early sag fill in the K20/K30 sequence was deposited as marine shales within a long (partially restricted) marine embayment. This deposition was punctuated by occasional regressive events, providing important reservoir facies on the inboard margin. The K20/K30 sequence is overlain by a regionally distinct marker (both seismically and lithologically) along the entire margin (Figures 7 and 9), which is termed the KA event. This event relates to the separation of Greater India from Antarctica and the establishment of open oceanic conditions (Figure10). KA marks the first flooding associated with the onset of a mature ocean phase (Bradshaw et al., 1988) and is recognised by a radiolarite-rich section which results from upwelling of deep oceanic water enriched in silica and more oxygenated oceanic circulation currents (Ellis, 1987). The K40 section forms the uppermost portion of the regional Cretaceous seal over the WASB area (Figure 7). Locally, K50 and K60 units can be shaley, forming sealing strata. Commonly underlying units down into the uppermost Jurassic are also shaley, but K40 is the most extensive shale unit and forms the ultimate regional topseal. During the Campanian, uplift of the hinterland (in response to rift events along the Australian southern margin), resulted in a phase of inversion in the Exmouth Plateau and Exmouth Sub-basin areas (Tindale et al., 1998; Bradshaw et al., 1998). This tectonic event marked the onset of transpressional structural growth of pre-existing rift related structures within the Barrow and Dampier sub-basins (e.g. Barrow Island). Further north in the Caswell Sub-basin, hinterland uplift resulted in a block rotation of the margin (tilt event on Figure 7), where sediments inboard of the tilt line were eroded and redeposited into deeper water environments (Blevin et al., 1998a). This regional tectonism is interpreted to be related to the far field plate movements, associated with the onset of Tasman Sea spreading (Figure 7) (Bradshaw et al., 1998). Further sand influxes into the Caswell and southern Vulcan areas occurred in the Maastrichtian, and following the base Tertiary onset of Coral Sea spreading (Figure 7), the North West Shelf had moved sufficiently far north for carbonate factories to be established in areas away from clastic input. Following a major plate re-organisation in the middle Eocene, Australia moved rapidly northwards, and carbonate deposition became dominant (Baillie et al., 1994). Reworking of carbonates from the factory tops led to massive carbonate progradation, infilling the underfilled accommodation space provided by the underlying rift basins. In the Neogene, the WASB was affected by further regional tectonism, in response to two processes. The first was restricted to the Bonaparte Basin area, and was the direct product of the collision of the irregular edge of the Australian plate with the Java-Banda arc system (Keep et al., 2002) (Figure 5). The second effect, which is dominant in the North Carnarvon and Browse basin areas, relates to the change in the regional stress field associated with the formation of the Irian-PNG Fold Belt (Hillis et al., 1997). This latter process accentuated the transpressional structures formed in the Campanian, and is also used to explain the formation of synchronous inversion structures in southeastern Australia (Dickinson et al., 2001). The timing of both Neogene events is shown on Figure 7. The New Guinea Fold Belt formed between about 12 Ma and 3 to 4 Ma (Hill and Raza, 1999) and the Sumba-Banda collision occurred between 8 Ma and 3 Ma (Keep et al., 2002). In New Guinea the end of the foldbelt phase was marked by a change from convergent to transpressional plate motion (Hill and Raza, 1999). In the Timor area the 3 Ma tectonic event records the cessation of Australian crust subduction into the Banda Arc, as it locally jammed the subduction system. Australia’s northward movement was maintained, however, by the initiation of a north-facing subduction zone along the Wetar and Flores thrust system (McCaffrey, 1996; Genrich et al, 1996). The 3 Ma tectonic event is also evident on areas of the Sundaland craton adjacent to Sumba where massive structural inversion events occurred (Bransden and Matthews, 1992), and a synchronous change in plate motions also occurs in the Pacific at this time (Pockalny et al., 1997). The 3 Ma event is thus likely to be an event of regional significance. The regional Neogene tectonism resulted in breach of some traps and release of hydrocarbons from existing hydrocarbon accumulations and the leakage to the seabed. It has been suggested by Hovland et al. (1994) that this seepage assisted in the formation of bioherms via the hydrocarbons providing nutrients for bacteria, which were, in turn, part of the food chain for organisms such as Halimeda codiacean algae. The association of leakage with surface biohermal mounds has also been noted by Bishop and O'Brien (1998) in the Nancar area and over the greater Timor Sea area by O'Brien et al. (2002). Since the 1970s it is has also been a suspected mechanism for the formation of the massive atoll over the Scott Reef field (Figure 3). However, whether all or just some of the Neogene to present-day reefs have been seeded from hydrocarbon leakage is not clear. O'Brien and Woods (1995) and Cowley and O’Brien (2000) also describe interpreted seepage-related amplitude anomalies from within the shallow sedimentary section (called hydrocarbon related diagenetic zones, HRDZs) which are present over many of the margin's accumulations. These features are believed to be formed by the emplacement of carbonate cements within shallow Tertiary sand units via the oxidisation of migrating thermogengic hydrocarbons. Exploration History {Figure Captions (22-28)}
The exploration history of
the North West Shelf is described by Purcell and Purcell (1994), and the history
of Australia’s exploration industry (including a history of the North West
Shelf), by Wilkinson (1991). Systematic exploration for hydrocarbons began in
the early 1950s with field mapping of onshore and island areas. Onshore seismic
followed, and the first exploration well was drilled at Rough Range 1 in 1953
(Fig. 2). Offshore exploration resulted in, with major The data on Figures 23, 24, and 25 are from Woodside’s proprietary database, which classifies all wells into exploration or non-exploration types. Many “exploration” wells that discovered extensions to known pools are reclassified in the Woodside database as appraisal wells. Similarly, "appraisal" wells that discovered new pools are classified as exploration wells. Thus, the total exploration well counts shown on Figure 22 (and on all other figures and tables in this paper) will not necessarily match other published well count data. The distribution of wells classified as genuine exploration wells is shown on Figure 2.
Woodside's database also
contains estimates of recoverable Discovery history plots on Figures 23, 24, and 25 do not include any measure of “reserves growth”, i.e. a measure of how the reserve estimate has changed through time. On these plots, the best estimate of the scope recoverable volume for the entire field is allocated to the spud date of the "discovery well". When a well first penetrates a hydrocarbon pool this well is deemed to be the “discovery well”, even though the significance of the discovery may not become clear for many years, and a later well may actually be credited with the “discovery”. Examples of this include North Rankin 4, which first penetrated the Perseus gas accumulation in 1972, whereas Perseus 1 was not drilled until 1996 (Taylor et al., 1998). In our database, therefore, the current scope Perseus reserve estimates are attributed to the North Rankin 4 well, and Perseus 1 is classified as an appraisal well. Similarly Hilda 1 drilled in 1974 is the discovery well for the Griffin/Ramilles Field (i.e. not Griffin 1, drilled in 1989), the discovery well for the Woollybutt Field was West Barrow 1 in 1982 (not Woollybutt 1, drilled in 1997), and Brewster 1 drilled in 1980 is the discovery well for the Gorgonichthys/Titanichthys/Dinichthys discovery made in 1999/2000.
The relative volume of
discovered The various trends illustrated on Figures 22 to 26 show that exploration on the North West Shelf has gone through four phases:- · The “Early Years” (1953-1970), with limited offshore drilling, where the only significant discoveries were Barrow Island (Barrow 1, 1964) and Legendre (Legendre 1, 1968). · The 1971-1980 “Big gassy fish in a barrel” era when most of the large gas fields were discovered on open grids of poor quality 2D seismic data (North Rankin, Goodwyn, Scott Reef in 1971, Gorgon and Brewster in 1980).
·
The 1981-1996
“2D seismic
·
The 1997-2001
“3D seismic There
has been a general increase in drilling activity, from 1-5 wells per year in the
early years, to an average of around 40 wells per year in the 3D era. This
exploration effort discovered approximately two-thirds of all the discovered
hydrocarbons during the “Big Gas” phase of exploration, when most of the primary
large structures were drilled. Since then, approximately 100 mmbbls of The main trap styles on the North West Shelf are simple drape anticlines (over underlying horsts), and horst/tilted fault block structures at the level of the base regional seal (Longley et al., 2002). Throughout the evolution of the margin, the main clastic sediment provenance was from the southeastern cratonic flank, so the stratigraphic level of top porosity beneath the regional seal (Figure 7) generally becomes progressively younger towards the cratonic edge (Figure 27). Regional Valanginian uplift in the south of the Exmouth Sub-basin, beneath the KV seismic event, has reversed this trend in part, and in other areas, isolated sands at shallower levels locally complicate the detail of the top porosity surface. Some 97% of all hydrocarbons discovered to date occur at this base regional seal level, even though numerous wells along the margin have tested traps at deeper levels, i.e., the concentration of hydrocarbons beneath the base regional seal is not a product of selective sampling – many wells have unsuccessfully tested deeper structures. Failure at many of these deeper levels is due to a lack of effective sealing units (topseal and flank seal for fault bounded traps). Rare effective sealing strata at other levels are present (Figure 7), however, to date, these traps contain an estimated 3.1% of the regions reserves being split into 2.2% within Palaeozoic units within the Petrel Sub-basin and 0.9% beneath Jurassic intra-formational seals (eg Lambert 2 gas discovery, Kingsley et al., 1998). Furthermore, only three significant hydrocarbon accumulations totalling some 0.2% of the margin's estimated reserves have been discovered above the regional seal (Maitland, Swan and Puffin; Figures. 3 and 7). All of these shallow occurrences are associated with obvious fault conduits, but in general, the regional seal is highly effective. The
distribution of the region's estimated reserves by phase and reservoir level is
shown on Figure 28. Most of the The main
trap styles present along most of the North West Shelf are easily identified by
good quality 2D seismic data. The advent of good-quality 2D seismic, and using
local well control to define the level of top porosity, meant that most of the
secondary simple traps on the WASB were identified and drilled during the “2D
seismic The primary impact of 3D on the North West Shelf has been: · The better definition (decreased range) of discovered resource volumetric estimates, prior to field development (e.g. Perseus, Taylor et al., (1998); Legendre, Willetts et al. (1999)); · The discovery of smaller nearfield traps, not readily apparent on 2D datasets; · To provide a consistent volume of seismic velocity data enabling the confident depth conversion of subtle traps (e.g. East Spar, Craig et al. (1997) and Woollybutt, Hearty and Battrick (2002); · To identify potentially complex structural and stratigraphic traps, based on amplitude and AVO (amplitude versus offset) analysis (e.g. Linda, Apache (2002); Enfield, Bussel et al. (2001). · To gain a better understanding of the geological evolution of the margin from the better imaging of deeper seismic events. The depth conversion impact of 3D on discovered volumes has been modest to date, since there generally has to be an inflection or structural nose on existing two-way time or velocity data, which the depth conversion process accentuates into a robust depth closure. These features, although significant, are by their very nature uncommon and, because of their subtle relief, they are very unlikely to contain large hydrocarbon volumes (e.g. greater than 100 mmbbls of recoverable reserves). The
amplitude and AVO impact of 3D data on exploration is proven through numerous
small discoveries, such as the amplitude supported onlap trap intersected by
Linda 1 in the Barrow Sub-basin (Apache, 2002), and the larger Enfield lowside
fault block Regional Petroleum Systems {Figure Captions (29-35)}
The concept of a simple source-reservoir couplet “petroleum system” as defined by Magoon and Dow (1994) is not readily applicable to the North West Shelf since:
·
There is no world class source
·
Source rocks are generally of poor
quality, and commonly occur at multiple stratigraphic levels. Products generated
from different levels are usually geochemically similar, and co-mingle during
migration (or in the reservoir), making the parent source units difficult to
identify using conventional · Many of the actual source units are difficult to identify, since some are undrilled, some contain source material dispersed over thick stratigraphic intervals, and others are developed within ephemeral facies which are rarely drilled and difficult to understand.
Notwithstanding the above, the petroleum systems operating on the North West
Shelf have been defined by Bradshaw et al. (1994) and Edwards et al. (1997) and
the work presented here builds on this foundation. Figure 29 presents a
simplified distribution map of the effective petroleum systems and the migration
style after Demaison and Huizinga (1994). These charge areas are schematic only
and their limits are poorly constrained. Individual areas are described in more
detail below, but the figure clearly demonstrates that many parts of the margin
do not contain an effective charge system. In some areas this may be due to an
insufficient sample population, but in other areas we believe this lack of
effective charge is due to absence of an effective source Neogene reactivation of the North West Shelf has historically focussed attention on trap breach as a major reason for many exploration well failures (O’Brien et al., 2002). Although undoubtedly a major risk in some areas (e.g. the Londonderry Terrace – Figure 2 and Brincat et al., 2001) this focus has tended to mask the importance of the underlying source risk. Trap risk is the primary suspect in many failed trap analyses because of the obsessive focus of exploration companies on seismic prospect mapping. There is always plenty of seismic data to purchase, analyse, reprocess and discuss, and a plausible mechanism for structural failure can generally be supplied. Conveniently, the structural failure hypothesis always preserves the supposed prospectivity of the area, and focus quickly moves to the adjacent prospect. In contrast, the presence of an effective source system is significantly more difficult to evaluate and understand. Prediction of maturity and migration issues can usually be evaluated by well control, seismic mapping, thermal and burial history modelling, but the key element which is always difficult to quantify is source quality and effectiveness. The intrinsically intangible nature of the source effectiveness risk element, and the blighting of entire areas once the absence of an effective source is established, has tended to popularise the trap breach myth. The conclusion of absence of source assumes enough wells have been drilled and evaluated to make this damning assessment. In an
attempt to better understand the source
Identifying With
this caveat in mind, and in the absence of any more rigorous method of
evaluating source potential, we attempted to map out the relative liquids
potential of different source sequences, using a statistical comparison of
source When
integrated with other geological and exploration data, the source
·
·
Source rocks are not identified in the
Barrow and Exmouth sub-basins (Figure 2), yet these areas contain numerous
·
The Beagle and Browse basins contain no
identified liquids-prone source
·
The TR20-TR10 (Triassic) section
appears to have little or no
·
There is some
·
Significant
·
There is significant The
observations above are consistent with the reservoir distribution of The
burial, maturation and migration of hydrocarbons from identified source Portions
of the WASB which are currently mature for gas are the central basinal areas
within the Barrow-Dampier, Caswell and Malita Sub-basins (Figures 2 and
34).
Burial history in these areas has resulted in the main source units (Figure 33)
passing through the Figures 18 to 21 highlight the progressive outboard (northwesterly) migration of depocentres from the Oxfordian (Figures 18 to 21) to the present day. The primary reason why most deepwater portions of the margin are generally gas-prone is because they lack Late Jurassic synrift source rocks and that the migration of depocentres outboard has also tended to focus charge from the Late Jurassic depocentres in an inboard (southeasterly) direction. It may
be stated that all of the major All
basinal areas are flanked by shelfal and platform areas, where Cretaceous
sealing units become thinner and/or faulting becomes more pervasive. In these
areas, a lower-impedence fault-related vertically-drained migration character
dominates. In these lower impedance areas, particularly those affected by
pervasive Neogene tectonism, such as the Vulcan Sub-basin, migration routes
between source and trap are short, risk of fault breach is significantly higher,
and risk of gas-flushing is significantly lower than in basinal high impedance
areas. Some portions of the North West Shelf (e.g. the central Barrow Sub-basin
and parts of the Vulcan Sub-basin) display both high and low impedance character
respectively for Apart from gas-flushing and the selective leakage of gas up faults, there are two processes which affect in situ reservoired hydrocarbons, and the resultant hydrocarbon phase. These are:-
·
Degradation of a light
·
Water-washing, acting upon a mixed The
former will only occur at low temperatures (below 70 to 80oC),
and biodegradation risk can readily be assessed. Water washing resulting in
enhancement of In summary, it appears that a gassy charge can be enriched in liquids via selective dynamic gas leakage and/or water washing, and an oily charge can be destroyed by gas flushing and/or biodegradation. The factors which affect the presence and phase of reservoired hydrocarbons along the North West Shelf are therefore complex, and go significantly beyond the traditional depth, pressure, temperature, source quality, maturity, migration and trap risk factors typically considered by explorationists. Four
source The
second model (Figure 35B) of
·
Certain wells show enriched source · Though the source potential is spacially erratic, where identified it tends to be repeated within stacked parasequences suggesting the enrichment mechanism is repeated in the same location and thus is probably structurally controlled · Both the marine shale and delta-top coals are within strongly interbedded sequences associated within facies either side of the delta front suggesting the source rocks were deposited within a deltafront area where frequent, widespread marine floods occurred. The
“delta front enrichment” source A fourth unproven model for liquids could be hydrocarbons sourced from deep water marls rather than marine shales with a significant higher plant input as found in the inboard failed rifts (Bradshaw, 2001; Summons et al., 1998). There is some geochemical evidence to suggest that the oils sourced from Mesozoic carbonate facies seen in Seram, Buton, Buru and Timor may also extend to the outer Bonaparte and Browse basins (Edwards et al., 2001) and to the Carnarvon Basin (George et al., 1998). This petroleum system is developed out beyond the typical Late Jurassic Westralian system (Bradshaw et al., 1994) of the North West Shelf. The
starting point for Woodside’s regional interpretation of fluid geochemistry was
the “Oils of Western Australia” study by AGSO/Geomark (1996). This systematic
review of 160+ oils and condensates emphasised the primary tectonic control on
source The new analyses help to identify differences due to maturity and secondary alteration from those fundamentally related to source. Until recently, very little published geochemical data was available for gases. Recent reports (AGSO/Geotech 2000; Boreham et al. 2001; Crostella and Boreham, 2000; Pallaser, 2000) have greatly improved matters but there is still a paucity of carbon isotope data for individual gas components. Such data are essential to gas typing and maturity estimation and in particular, to recognising mixtures of thermogenic and biogenic gas. Petroleum Geology of the Main Productive AreasThe petroleum geology of the various sub-basins and areas along the North West Shelf is described below. At the
end of 2001 the North West Shelf contained some 233 field discoveries and
754 exploration wells indicating an historical technical success rate of 32% and
a 12% historical success rate for fields greater than 20 mmboe. The margin is
estimated to contain (scope) reserves of 152 Tcf of gas, 2603 mmbbls of
condensate and 2557 mmbls of
Exmouth Plateau (Figures 2, 3, 20, 29) The
Exmouth Plateau at the end of 2001 contained 11 discoveries and 23 exploration
wells with a historical technical success rate of 74% and a 35% historical
success rate for fields greater than 20mmboe. The plateau is estimated to
contain (scope) reserves of 32 Tcf of gas, 81 mmbbls of condensate and no The petroleum geology and early exploration history of the Exmouth Plateau is described by Barber (1988). The Exmouth Plateau contains a number of large Cretaceous (K10) dry gas accumulations including Scarborough, and Jansz/Io (reservoired in J40 fan sands - see Bussel et al., 2001) and a number of large Triassic (TR20) dry gas accumulations such as Orthrus and Maenad inboard (Figures 2 and 29) plus smaller gas pools intersected in Jupiter, Sirius and Eendracht (Figure 3). All these accumulations have the majority of their reserves reservoired at the base regional seal level. The sandiness of the stratigraphy beneath this level generally precludes significant intra-Triassic (TR20 and TR10) accumulations, and enables effective vertical migration to regional top porosity level. Evidence of trap breach is present on seismic data, explaining why some traps (e.g. Jupiter) are underfilled. TR20 and younger sequences are immature, and the dry gas is consequently interpreted to have been sourced from TR10 delta top sediments, as penetrated by Jupiter 1. Gas in the large Scarborough field (4 TCF) (Longley et al., 2002; Bradshaw et al., 1998) is both extremely dry (C1/(C1-C4 = 0.998) and low in CO2 (trace). This composition and the relatively shallow/cool reservoir suggest a biogenic origin, however, the methane isotope value of minus 42.3 (Crostella and Boreham, 2000) is more consistent with a thermogenic source. Furthermore, biodegraded gases at Sirius and Eendracht are at least partly thermogenic (James and Burns, 1984), and consistent with a Middle Triassic (TR10) coaly source. Assuming that the composition and carbon isotope values of Scarborough gas are both valid, it could be an end-stage anaerobic biodegradation product of an initially dry, thermogenic gas. In the absence of isotope data for the CO2, an early thermal origin is also possible. The Exmouth Plateau was strongly affected by Campanian structuring (Bradshaw et al., 1998) and the largest inversion structure is Scarborough, which is still at the bathymetric crest of the plateau (Figure 3). Significant Tertiary burial occurs inboard of this area (Figure 20), and TR10 in the (uninverted) synclinal area is interpreted to be at maximum depth of burial, and still supplying gas to reservoirs at the base regional seal level.
Dampier, Barrow and Exmouth sub-basins (Figures 7, 14, 33, 34) The
principal effective Dampier Sub-basin (Figures 2, 6, 7) The
Dampier Sub-basin is described by Woodside (1988) and Jablonski (1997). At the
end of 2001 it contained 49 field discoveries and 120 exploration wells,
with a historical technical success rate of 41% and a 22% historical success
rate for fields greater than 20 mmboe. The sub-basin is estimated to contain
(scope) reserves of 34 Tcf of gas, 1037 mmbbls of condensate and 633 mmbls of
The
Dampier Sub-basin can be divided broadly into two structured flanks, either side
of the main Oxfordian depocentre (Figures 2 and
6). Fields along the western
flank include the large rift-related horst block traps, such as the Goodwyn
(Young, 1998), North Rankin (Vincent and Tilbury, 1988) and Echo-Yodel wet gas
fields, the single, unique, Perseus lowside saddle trap (Taylor et al., 1998),
and numerous other smaller horst and tilted fault block traps such as Eaglehawk
(Vincent and Tilbury, 1988), and the Searipple field beneath Perseus (Taylor et
al., 1998). Subcrop of different J10 and TR20 sands within many traps at the
level of the base regional seal produce complex fields containing various
hydrocarbon phases ( The accumulation of significant volumes of hydrocarbons at multiple stratigraphic levels along both flanks and within the main basinal area demonstrates the laterally drained high-impedance nature of the petroleum system within the central Dampier Sub-basin. In the
Dampier Sub-Basin the complex charge history is reflected in the recognition of
five distinct fluid families (AGSO/Geomark, 1996). Most
oils in the Dampier Sub-Basin are sourced from marine or marine-deltaic
sediments such as those in the Late Jurassic of the Kendrew and Lewis Troughs
(J40, Kimmeridgian and Oxfordian). The oils at Eaglehawk 1, Egret 1 and some of
the North Rankin condensates, however, show evidence for a source containing a
higher proportion of land-plant matter. In the case of Egret, the The
imprint of an early, biodegraded Barrow Sub-basin (Figures 2, 7, 11, 12, 16, 18, 27, 33) The
Barrow Sub-basin is described by Parry and Smith (1988) and Baillie and Jacobson
(1997). The Barrow Sub-basin at the end of 2001 contained 77 field discoveries
and 202 exploration wells with a historical technical success rate of 38% and a
8% historical success rate for fields greater than 20 mmboe. The sub-basin is
estimated to contain (scope) reserves of 21 Tcf of gas, 113 mmbbls of condensate
and 913 mmbls of The
Barrow Sub-basin, like the Dampier, can be divided into a western and eastern
flank surrounding a central deep. The outboard northern end of the western flank
(Figure 2), along the Gorgon platform, contains large dry TR10 and TR20 gas
fields such as Gorgon, West Tryal Rocks (McClure et al., 1988), Chrysaor,
Dionysus, Geryon (Sibley et al., 1999), and Iago. All of these contain gas
within simple horst traps at the base regional seal level. As for the Rankin
Platform traps to the north, these fields have intraformational Triassic seals
subcropping the base regional seal resulting in numerous pools with different
fluid contacts (Sibley et al., 1999). The southern end of the western flank
(Alpha Arch) contains K20 The lack of observed source potential in Barrow and Exmouth sub-basins from the Woodside source screening work (Figure 33) is interpreted to be due to burial of the main J40 source sequence beneath thick K10 Barrow sequence of deltaic sediments (Figure 18), with the result that it is rarely drilled, and often overmature where penetrated. Volkman
et al. (1983) correlated some Barrow Sub-Basin oils to the Late Jurassic Dingo
claystone (J50/J40). A more specific assignment was made on the basis of
aromatic biomarkers by van Aarssen et al. (1996), who observed that most oils
correlated best with the W. spectabilis biozone (J40 Oxfordian). While a
Late Jurassic origin of most of the oils is likely, there is evidence for
contribution from other source rocks at some locations. For example, a
calcareous source component is suggested by biomarker profiles of North Herald
and Chervil oils, and for an early Gases of the Gorgon area, especially those in reservoirs associated with deep, high angle faults, are higher in CO2 and much lower in liquids content than analogous fields of the Rankin Platform. This is in part due to the deeper burial of source units within the adjacent basinal area, but also due to flushing of earlier (wetter) gases via a spill chain passing from Gorgon (south to central to north) to Chrysaor, Dionysus and Geryon, with a late dry, CO2 rich charge. It is possible that the J20 section may be responsible for much of the liquids content in the Dampier gas fields (as is the case at Angel) and since the J20 delta top sediments were limited to the Dampier area and did not extend into the Barrow rift (Figures 11 and 12) the initial charge into the flanking Gorgon area traps may have been relatively dry gas. In addition, the amount of erosion at the base regional seal level is greater in the Gorgon area and little or no delta top sediments within the J10 or J20 units remain to provide a wet gas charge as they may do in the Rankin Platform area. Condensates in the Gorgon Platform fields are highly aromatic, and both saturated and aromatic biomarkers show evidence of mixing (AGSO/Geomark, 1996; AGSO/Geotech, 2000; van Aarssen et al., 2000). It is therefore considered likely that the liquids and gas components of the Gorgon gases are decoupled with respect to source and maturity, and in fact the liquids may be the result of gas stripping of mature coal organic matter in the reservoir and/or along the migration pathway. Such considerations reduce the relevance of biomarker information in assigning a source for the gas. Furthermore, in the absence of information on kerogen isotopes it is not possible to deconvolute source and maturity influences on the gas isotope signature. As noted in the AGSO/Geotech study, however, uniformity in the isotope composition of wet gas components argues for a common source for most Carnarvon Basin gases, including those of the Gorgon complex. Since Jurassic sediments are downthrown to great depth by the faults forming the Gorgon fields, a Triassic source is not necessary to explain a dry gas charge here. Gases in
the Barrow Sub-Basin often appear to contain a component of biogenic methane (AGSO/Geotech,
2000). This is apparent from the isotope signature wherein methane is
isotopically anomalously light, relative to ethane in the same accumulation.
In cases where biogenic methane occurs with biodegraded oils it is probably of
secondary biogenic origin, i.e. formed as a by-product of anaerobic degradation
of The deep
basinal areas of the Barrow Sub-basin adjacent to the Gorgon and Alpha arches
(Figure 2) has a thick Cretaceous shale section with the base regional seal at
the TR20 stratigraphic level (Figure 27) and this shale pile is overpressured
due to disequilibrium compaction (Tingate et al., 2001). Southwards and
eastwards from this shale depocenter the Cretaceous section becomes more
interbedded with deltaic and fan sands of J20-K10 age and overpressure and gas
flushing is less dominant and mixed The
Exmouth Sub-basin is described by Tindale et al. (1998). At the end of 2001 the
area contained 16 field discoveries and 74 exploration wells with a historical
technical success rate of 22% and a 8% historical success rate for fields
greater than 20 mmboe. The sub-basin is estimated to contain (scope) reserves of
1.2 Tcf of gas, 0 mmbbls of condensate and 278 mmbls of The
Exmouth Sub-basin only has significant hydrocarbon accumulations on it’s eastern
flank, due to strong tilting down to the northwest. The main accumulations
include the K10 Macedon/Pyrenees faulted anticline dry gas field (probably
produced from biodegradation of All of
the Vinceint, Enfield and Laverda fluids are heavily biodegraded (both A group
of oils with much stronger terrestrial affinity than those of the main
Barrow-Dampier-Exmouth family are found in the eastern part of the Exmouth
Sub-Basin (Figure 29). These include Leatherback, Blencathra, Outtrim and Rough
Range. The oils show varying degrees of terrestrial influence in their biomarker
profiles, and are all relatively waxy. The Rough Range crude is regarded as an
end member, with no marine influence, and it appears to originate entirely from
coals or lacustrine shales. Callovian (J30) sediments in Leatherback 1 show a
reasonable
Beagle Sub-BasinThe
geology and early exploration in the Beagle Sub-basin area is described by
Blevin et al., 1994. The Beagle Sub-basin at the end of 2001 contained one field
discovery (the Nebo Field; Osborne, 1994) and 17 exploration wells with a
historical technical success rate of 6% and a 0% historical success rate for
fields greater than 20 mmboe. The undeveloped Nebo field is estimated to contain
up to 5mmbbls of recoverable The Nebo
The
Beagle Sub-basin has several wells on robust structural traps which were thought
to have failed due primarily to trap breach (Blevin et al., 1994). Fair source
The offshore Canning Basin is described by Horstman and Purcell (1988), Lipski (1994), Colwell and Stagg, (1994), and Smith et al. (1999). The basin is relatively underexplored but large long-lived structures at the base regional seal (particularly the Bedout structure) are devoid of hydrocarbons and it is strongly suspected that there may be no effective hydrocarbon charge within most parts of the basin. The
offshore Canning Basin at the end of 2001 contained one undeveloped discovery
(Phoenix) and nine exploration wells with both a historical technical success
rate and a historical success rate for fields greater than 20 mmboe of 11%. The
Phoenix field is estimated to contain (scope) reserves of 500bcf of gas with no
condensate or Browse Basin (Figures 2, 7, 8, 9, 12, 18, 29, 33, 34) The
petroleum geology of the Browse Basin is described by Maung et al. (1994),
Struckmeyer et al. (1998) and Blevin et al.(1998a, b). The Browse Basin at the
end of 2001 contained 19 field discoveries and 59 exploration wells with a
historical technical success rate of 32% and a 14% historical success rate for
fields greater than 20 mmboe. The basin is estimated to contain (scope) reserves
of 35 Tcf of gas, 722 mmbbls of condensate and 15 mmbls of The
Browse Basin resource base is dominated by the large J20 Scott Reef, Brecknock
and Brecknock South horst block dry gas fields (Figures 2 and
7) (Longley et al;
2002 and Bint, 1988) that have been discovered outboard of the main Caswell
Sub-basin source kitchen area (Figure 34). Inboard of this depocentre are the
relatively small K30 Gwydion and K40 enigmatic Cornea basement drape fields
(Spry and Ward, 1997; Ingram et al., 2000) which contain both gas and The Central Caswell Sub-basin is currently in the gas window at the J20 level and the basin is devoid of thick anoxic J40 marine shales except for locally in the north adjacent to the Brewster Field, where an extension of the J40 Vulcan rift basins system (the Heywood-Anderton graben) extends into the Northern Browse Basin area. Good
Late Jurassic The gas
potential of the Early-Middle Jurassic is highlighted by the giant gas fields at
Scott Reef, Brecknock and Brecknock South. These gases have low CGRs
(around 20 bbls/MMscf), compared with fields in the Carnarvon Basin, and yet the
liquid fraction boiling range extends to beyond C30. Thus, in many
respects they resemble an
Elsewhere in the Browse Basin, the pervasive Middle Jurassic gas charge is
supplemented to varying extent by liquids derived from Late Jurassic and Early
Cretaceous marine shales (J40 and K30 respectively). The Gwydion, Cornea and
Caswell 2 oils are all interpreted to be the product of K10-K20 (Early
Cretaceous)
Vulcan Sub-basin (Figures 2, 12, 33, 34) The tectonostratigraphy of the Vulcan Sub-basin is described by Pattillo and Nicholls (1990) and the structural evolution of the area is summarised by Woods (1994). The
Vulcan Sub-basin at the end of 2001 contained 18 field discoveries and 67
exploration wells with a historical technical success rate of 27% and a 13%
historical success rate for fields greater than 20 mmboe. The sub-basin is
estimated to contain (scope) reserves of 1.3 Tcf of gas, 31 mmbbls of condensate
and 357 mmbls of The
Vulcan Sub-basin contains numerous large J40 Source
rocks in the Vulcan Sub-basin are stratigraphically extensive, with good liquids
potential occurring throughout the J20-K30 Jurassic and Early Cretaceous section
(Figure 33). Evaluation of our The
multiple source levels present in the Vulcan are reflected in the character of
the fluids, many of which show mixed sourcing. Most oils can be correlated to
marine shales of the J40 section but the The
Vulcan Sub-basin is ‘oily’ because the area contains Sahul, Flamingo and Nancar Area (Figures 3, 13, 33, 34) The
tectonostratigraphic evolution of the Sahul, Flamingo and Nancar area is
described by Whittam et al. (1996) and the source geochemistry is described by
Preston and Edwards (2000). A water washing model is described for the Laminaria
area by Newell (1999). At the end of 2001, the area contained 19 field
discoveries and 74 exploration wells with a historical technical success rate of
26% and a 7% historical success rate for fields greater than 20 mmboe. The area
is estimated to contain (scope) reserves of 3.4 Tcf of gas, 233 mmbbls of
condensate and 337 mmbls of The
Sahul-Flamingo-Nancar area contains numerous significant In the
Nancar Trough, Laminaria High and Flamingo High area, source rocks occur at all
levels, from the J20 (Early-Middle Jurassic) deltaic section through to the
K20-K30 sequence (Figure 33) (Preston and Edwards, 2000). A thin interval of the Echuca Shoals Formation, near the base of K20, displays high gamma response and
excellent source potential based on High
quality J30 (Callovian) marine shale The large Bayu-Undan gas field at the southern end of the Flamingo Syncline area has not been sourced from the Northern Flamingo Syncline because it has a hydrocarbon contact which is deeper than the spill chain of oils running out of the Flamingo Syncline area. It is either:-
·
locally charged from the same J40-J30
source section as the · or it is a mixture of locally sourced liquids with gas migrating out for the Malita Graben area to the south. The
Flamingo Syncline area is the model area for the “delta front ponding” source
Oils and
core extracts from the very small volumes of The
Sahul-Flamingo-Nancar area is an ‘oily’ area since most of the source rocks lie
within the
Greater Kelp-Sunrise High and Malita Graben (Figure 34)The
petroleum geology in the Malita Graben and Sunrise High area is described by
Mory (1988) and the area is adjacent to the study area described by Whittam et
al. (1996). The combined Greater Kelp-Sunrise High and Malita Graben areas at
the end of 2001 contained 7 field discoveries and 16 exploration wells with a
historical technical success rate of 43% and a 31% historical success rate for
fields greater than 20 mmboe. The sub-basin is estimated to contain (scope)
reserves of 20.2 Tcf of gas, 379 mmbbls of condensate and 0 mmbls of The giant Sunrise - Troubadour gas-condensate field (Seggie et al., 2000; Longley et al., 2002) and gas at Evans Shoals, Lynedoch and Chuditch are large faulted anticlinal structures at the base regional seal level. The former was formed by Neogene structuring (at about 3 Ma) and the latter fields are deeply-buried rift-related terrace and tilted fault blocks associated with the Tithonian formation of the Malita Graben. The gas in all fields originates in J20 fluvio-deltaic sediments (Middle Jurassic). The major kitchen area for this charge is the Malita Graben and Troubadour Terrace, to the southeast of the Sunrise High. The central basin area is currently gas-mature (Figure 34) and the thick regional seal has resulted in a laterally drained, high-impedence basin style where the base regional seal level appears to be flushed by gas. AGSO/Geomark (1996) suggested a calcareous element in the source of the Sunrise 1 and Troubador 1 condensates on the basis of biomarker work. The biomarker content of these fluids is however, extremely low, and recent work employing more sensitive methods, and including samples from the more recent Sunrise 2 and Sunset/Sunset West 1 wells does not support this interpretation. Gas and condensate isotope data infer that both the Evans Shoals 1 and Chuditch 1 gases are mixtures. For Evans Shoals, anomalies in the isotope composition of isobutane and isopentane have been interpreted as evidence of biodegradation (AGSO/Geotech, 2000), which seems unlikely given that the reservoir is currently buried to over 3.5 km. The Chuditch gas-condensate shows a disconnect between the gas and liquid range isotopes, suggesting mixing of a dry gas charge from the Malita Graben, with liquids from a less mature kitchen. Very d13C enriched methane in the Kelp Deep 1 gas implies that it was expelled from a Permian source (PZ 50) at relatively high maturity. Petrel Sub-basin and Bonaparte Inboard Shelf Areas (Figure 26)The
Petrel Basin area is described by Colwell and Kennard (1996), McConchhie et al.
(1996) and Edwards et al. (1997), and the Bonaparte Inboard Shelf area is
described by Gorter et al. (1998). The Petrel Sub-basin and Bonaparte Inboard
Shelf at the end of 2001 contained 18 field discoveries and 65 exploration wells
with a historical technical success rate of 28% and a 8% historical success rate
for fields greater than 20 mmboe. The sub-basin is estimated to contain (scope)
reserves of 3.9 Tcf of gas, 7 mmbbls of condensate and 19 mmbls of The
large gas fields in the area include older discoveries such as Petrel and Tern
(Gunn, 1988b) and the more recent discoveries of Rubicon and Blacktip. All of
these discoveries are faulted anticlines (some salt-cored) or tilted fault block
traps at the regional base Triassic seal level, and contain dry gas within PZ50
(Permian) sands. The The
Turtle and Barnett oils correlate with a Carboniferous (PZ30) marine shale seen
in onshore mineral exploration wells (Edwards et al., 1997) but not yet observed
in offshore wells. By contrast, the Petrel and Tern gas accumulations are
attributed to Permian fluvio-deltaic sediments, largely on the basis of their
d13C
enriched isotope composition. There is some danger of interpreting every
isotopically heavy fluid as Permian in origin as high maturity can also be
responsible for enrichment in
d13C,
however, similarities in the fluid signature to stains and inclusion oils at
Torrens 1 to the west emphasise the widespread viability of the Permian source.
The liquids potential of this system is yet to be proven, although palaeo-
SummaryThere
are large portions of the North West Shelf that do not contain effective
hydrocarbon source Within
areas that do have effective source
·
Areas with thick Cretaceous sections
with laterally-drained, high-impedance migration from gas-mature J20 deltaic
source
·
Areas with thin Cretaceous sections
where J40 (and/or J20/J30
·
Areas with thin Cretaceous sections
where J40 (and/or J20/J30 Other generally gassy minor petroleum systems falling outside of the above petroleum system types do exist on the Exmouth Plateau and within the Petrel Sub-basin. Remaining Potential (Figures 23, 25, 27, 35)
A
comparison of the estimates of the remaining hydrocarbon potential for the major
basins of the North West Shelf has been made by Powell (2001) and the preferred
published P50 estimates after AGSO are 1330 mmbbls of
|
|
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AcknowledgementsThe authors acknowledge both the contribution from the many geoscientists who worked at Woodside over the last 40 years and the contribution that both Woodside’s numerous joint venture partners and particularly Geoscience Australia (formerly AGSO) has made to the ideas and content of this paper. The authors also recognise the significant contribution former Woodside employee Dariusz Jablonski made to the study results. |
|
1. North West Shelf location
map.
2. North West Shelf areal
subdivisions, distribution of exploration wells and location of key wells.
3. Major hydrocarbon field
locations and regional bathymetry map of the North West Shelf.
4.
Regional JO seismic event (Oxfordian) depth structure map. Locations A-H show
the locations of the schematic cross-sections illustrated in
5. Simplified regional
tectonic elements map (modified after AGSO, 1994), illustrating the extent and
timing of major block rotations. 
6. Simplified regional
geological cross-sections. Section locations are shown on
7. Chronostratigraphic
summary of the North West Shelf. 
8. Simplified
palaeogeographic map of the upper TR20 Triassic sequence (Norian).
9. Chronostratigraphic Post-Palaeozoic
summary of selected North West Shelf sub-basins.
10. Simplified Pleinsbachian
plate reconstruction and sequence of major block rifting/separation events
affecting the North West Shelf. 
11. Composite map of JP1-JO
isopach map (J20 + J30 sequences) in the Northern Carnarvon Basin and offshore
Canning Basin area and TR-JO (TR10+Tr20+J10+J20+J30) isopach map in the Browse
and Bonaparte basins area.
12. Simplified J20 sequence (Sinemurian
- Callovian) palaeogeographic map.
13. Simplified J30 sequence (Callovian)
palaeogeographic map.
14. Simplified lower J40
sequence (Oxfordian) palaeogeographic map.
15. Simplified lower J50
sequence (Early Tithonian) palaeogeographic map.
16. Simplified K10 sequence (Berriasian
- Valanginian) palaeogeographic map.
17. Simplified K20 sequence (Valanginian-Barremian)
palaeogeographic map. 
18. JO (Oxfordian) to KV (Valanginian)
isopach map incorporating the J40, J50 and K10 sequences.
19. KV (Valanginian) to KA (Aptian)
isopach map.
20. KA (Aptian) to T (base
Tertiary) isopach map. 
21. T (base Tertiary) to
water bottom isopach map. 
1. Summary of main North West
Shelf megasequence boundaries.
22. Historical summary
(1953-2001) of exploration along the North West Shelf showing by year
23. North West Shelf
hydrocarbon discovery history curve by phase (mean success volume [MSV] for gas,
condensate and 
24. North West Shelf
hydrocarbon discovery history curve by geographic area against exploration well
count. 
25. North West Shelf 
26. Historical (from 1965 to
2001) Woodside permit coverage, current limits of 3D seismic data and summary of
estimated 
27. North West Shelf
simplified map illustrating top porosity beneath the regional seal.
28. Distribution of 
29.
Simplified petroleum systems map of the North West Shelf.
30. Histogram and cumulative
probability distribution summary of observed Total Organic Carbon (TOC)
measurements from 
31. Histogram and cumulative
probability distribution summary of observed Hydrogen Index (HI) measurements
from 
32. Comparison between
Hydrogen Index (HI) measurements from 
33. Summary of observed 
34.
Regional interpreted current day maturity at the JO (Oxfordian) surface over the
North West Shelf.
35. Summary of source 
