2016 Release Areas

Calder Graben

Release Area NT17-1, offshore Northern Territory

Highlights

Bids close on Thursday 19 October 2017

Adjacent to Barossa, Caldita, Evans Shoal and Evans Shoal South gas accumulations
Shallow to moderate water depths, 80–370 m
Plays include rollover anticlines, horst structures, drape and unconformity traps
Multiple potential oil- and gas-prone source rocks in the adjacent depocentre
This release area is considered to be lightly explored, refer to supporting information
Further guidance available, refer to 2017 Special Notices

Release Area NT17-1 straddles the Calder Graben, Malita Graben and Darwin Shelf of the northern Bonaparte Basin, and the westernmost Money Shoal Basin (Figure 1). Recent drilling in the area include the Barossa Field appraisal wells (2014-15), Blackwood 2 (2013), Evans Shoal North 1 (2013) and Heron South 1 (2012). The Release Area lies approximately 250 km offshore from Darwin.

The Malita Graben and Calder Graben form a major northeast-trending rift system that lies between the Petrel Sub-basin, the Darwin Shelf and Money Shoal Basin to the south, and the Sahul Platform to the north (Figure 1). The graben were initiated by Early Jurassic rifting associated with the break-up of Gondwana and contain a thick (up to 10 000 m) succession of late Paleozoic to Mesozoic sedimentary rocks (Figure 2) overlain by Cenozoic sedimentary rocks. The Darwin shelf and Money Shoal Basin, to the south and east respectively, have relatively shallow basement with a thin Jurassic succession overlain by thicker Cretaceous and younger sediments. The succession accumulated mostly due to passive subsidence. Late Cretaceous to recent faulting in the Release Area was formed by compressional reactivation relating to the convergence between the Australia-India plate and Southeast Asian microplates to the north.

The fluvio-deltaic Jurassic Plover Formation is the primary source and reservoir for the Sahul Platform, Troubadour Terrace, Malita Graben and Calder Graben gas accumulations. Gas shows have also been found in fractured carbonates of the Lower Cretaceous Darwin Formation, and sandstones of the Upper Jurassic Elang Formation and Upper Jurassic–Lower Cretaceous Frigate Shale. Condensate sourced from the Cretaceous Echuca Shoals Formation (e.g. Blackwood 1ST1) indicates there could also be an underexplored liquids play in the region.

Potential play types including inversion anticlines and submarine fans are depicted in Figure 3.

Petroleum systems elements

Northern Bonaparte Basin

Sources	Lower Cretaceous marine claystones of the Echuca Shoals Formation Upper Jurassic–Lower Cretaceous marine claystones of the Frigate Shale Middle–Upper Jurassic marine claystones of the Elang and Laminaria Formation Lower to Middle Jurassic fluvio-deltaic to marine Plover Formation
Reservoirs	Upper Cretaceous Puffin Formation basin floor fan sandstones Lower Cretaceous Darwin Formation fractured carbonates Upper Jurassic–Lower Cretaceous turbiditic and slope fans of the Sandpiper Sandstone Upper Jurassic–Lower Cretaceous shallow marine sandstones of the Frigate Shale (Flamingo Formation) Middle–Upper Jurassic deltaic to marine Elang Formation fractured and porous sandstones and carbonates Lower–Middle Jurassic fluvio-deltaic to marine Plover Formation
Seals	Regional seals Paleocene marine carbonates of the Johnson Formation Lower Cretaceous marine claystones of the Echuca Shoals Formation Upper Jurassic–Lower Cretaceous marine claystones of the Flamingo Group Intraformational seals Upper Cretaceous Wangarlu Formation micaceous marine shales and claystones Upper Jurassic marine siltstones and claystones of the Laminaria (Elang) Formation
Traps	Faulted anticline, tilted fault block, draped fault blocks, horst and graben, unconformity, and stratigraphic traps Speculative foot-wall fault traps on the down-thrown side of bounding faults on the Troubadour Terrace (Figure 4b)

Well Control

No wells have been drilled in Release Area NT17-1. However, several wells have been drilled in the Calder Graben adjacent to the Release Area including Lynedoch 1, 1A and 2, Barossa 1‑4 and Caldita 1‑2. Seismic data coverage for the region is indicated in Figure 5.

Lynedoch 1 ST1 (1973)

Lynedoch 1 was drilled in 247 m of water by Shell Development (Australia) Pty Ltd (1973) about 350 km north-northwest of Darwin. It was the first well drilled in the Calder Graben, and the second well to be drilled in the northern Bonaparte Basin. The well targeted a seismically defined, low-relief anticlinal structure mapped at the near base-Albian seismic horizon (labelled ‘P’ in the well completion report, or base of the limestone unit within the Darwin Formation, and interpreted as the Aptian Disconformity by Shell Development [Australia] Limited [1973]). There was no closure at either the Upper Cretaceous or Cenozoic levels. Lynedoch 1 was sidetracked when the drill pipe became stuck in tight Cretaceous shales and a fish was lost in the hole. The sidetracked Lynedoch 1 ST1 penetrated a thick Cenozoic to Jurassic succession of sedimentary rocks and reached a TD of 3967 mRT within Valanginian (Oxfordian in WCR) sediments (Flamingo Group) (Figure 4a). A thin (9.7 m) gas-bearing zone was encountered within a limestone unit (3674–3715 mRT) of the Darwin Formation, but it was not tested. Methane to butane was reported in the gas kick at 3698 mRT. Porosities range from 8% to18% over a depth of 3689–3715 mRT, with low gas saturation occurring in the matrix and higher gas saturation occurring in the fractured zones. Log analysis indicates a further zone of possible gas saturation in water-bearing sandstones of the Jurassic upper Flamingo Group. As the Bathurst Island Group limestone reservoir was thin and the Jurassic sandstones were tight in this well, the Mesozoic structures in this area were interpreted to be uneconomic for hydrocarbons.

Beluga 1 (1992)

Beluga 1 was drilled on the Bathurst Terrace which flanks the southern margin of the Malita Graben (BHP Petroleum Pty Ltd, 1992). It was drilled to evaluate a structural/stratigraphic play comprising an Upper Jurassic sand-dominated fan (referred to as the Beluga Sequence), sealed by the transgressive marine claystones of the Flamingo Group (Figure 4c). The closure is modified to the southeast by down-to-the-basin normal faulting. The results from this well are discussed in detail by Anderson et al (1993), but they do not use the same informal stratigraphic nomenclature (‘Jacaranda’, ‘Beluga’ and ‘Tuatara’ formations) presented in the well completion report. The well reached a TD of 3100 mKB in the Plover Formation and encountered gas indications in the Bathurst Island Group, and gas shows within the Flamingo Group and Plover Formation. The most significant gas shows and hydrocarbon fluorescence were encountered in tight Flamingo Group argillaceous sandstones within the Beluga Sequence [re-interpreted as the Sandpiper Sandstone]. The lower Flamingo Group (informal ‘Beluga Formation’) which was the primary reservoir objective, was deposited in a distal shelf or upper slope environment, away from the clastic source. Abundant detrital clay, silica and minor carbonate cement, and physical compaction account for the low porosity (average 10%) and very low permeability (<1 mD) of the lower Flamingo Group. Dip analysis suggests that the dominant sediment transport direction was southwards from a broad continental shelf on the Sahul Platform. Reservoir quality may increase in more proximal facies to the north. Quartz sandstones of the fluvial to shallow marine Plover Formation were also found to be tight due to silica cement and quartz overgrowth (average porosity 6%). Base seal, which was considered a significant pre-drill risk, was provided by the base of the coarsening-upward ‘Beluga Formation’. Source potential of the Upper Jurassic to Lower Cretaceous claystones was found to be relatively poor, showing an affinity for the generation of gas to light oil. The Middle Jurassic Plover Formation is considered to be early mature, based on a vitrinite reflectance measurement of 0.6%.The apparent sediment source direction for the Upper Jurassic sequences and present structural geometry indicates that significant basin inversion occurred during the latest Jurassic to Early Cretaceous.

Lynedoch 2 (1998)

Lynedoch 2 was drilled 13 km northeast of Lynedoch 1 in 1998 by Shell Development (Australia) Limited (1999) in a water depth of 266 m. The primary objective was to test the Lower–Middle Jurassic Plover Formation, with the Lower Cretaceous Darwin Formation as the secondary objective. The claystones and marls of the Wangarlu and Vee formations (Bathurst Island Group) provide vertical and lateral seals. Gas saturated sands were intersected in the Elang and Plover Formations. Although gas shows were encountered to TD, the Elang and Plover formation sands were generally tight with porosities ranging from 2.4% to 8.7% and core permeability generally less than 0.5 mD. The gas sample contained 4.3% CO₂ and 3.3 bbls/MMscf condensate (ConocoPhillips Exploration Australia Pty Ltd, 2008a). No production testing was conducted. The well reached a TD of 4225 mDF within the Plover Formation. The well was plugged and abandoned as a dry hole with gas shows.

Caldita 1 & 2 (2005, 2007)

Caldita 1 was drilled in 2005 in permit NT/P61 (ConocoPhillips Exploration Australia Pty Ltd, 2007) to test Elang and Plover sandstones within a large faulted anticline. Gas bearing sands were encountered in the Flamingo Group (3630–3644 mRT containing 11.4 m net sand with 9.6% average porosity, and 3685–3730 mRT containing 26.8 m net sand with 8.3% average porosity), the Elang Formation (3730–3871 mRT, containing 99.1 m net sand with 8.2% average porosity) and the Plover Formation (3871‑4037mRT, containing 109.7 m of net sand with 9.8% average porosity). Drill stem test (DST 2) over the interval 3756–3910 mRT flowed gas at a rate of up to 33 MMscfd (0.9 MMm³/d). Caldita 1 was reported as a gas discovery with P50 reserves of 2.9 Tcf (82 Bm³) of gas (Melbana, 2006). The well reached a TD of 4037 mRT within the Plover Formation. Caldita 2, located 6 km west-northwest of Caldita 1, was the field’s first appraisal well (ConocoPhillips Exploration Australia Pty Ltd, 2008b). The primary objectives were the Elang and Plover formation reservoirs as intersected in the discovery well. Gas saturated sands were identified in the Wangarlu, Darwin, Echuca Shoals formations and the Frigate Shale (identified as Flamingo Group in the WCR). The Frigate Shale (3653.1‑3887.0 mRT) had 22.1 m net reservoir sand with an average porosity of 8.3%. The Elang Formation (3887.0‑3975.0 mRT) intersected 11.0 m net reservoir sand with an average porosity of 5.3%. The well was drilled in a water depth of 136.5 m and reached a TD of 3972 mRT. No testing was carried out in this well. The Caldita 3D MSS seismic survey, acquired in mid 2016, and additional drilling will assist in the appraisal of the Caldita field (ConocoPhillips, 2016).

Barossa field (2006-present)

Barossa 1 ST1 was drilled in 2006 at a water depth of 233 m in petroleum exploration permit NT/P69 to test the Lynedoch gas accumulation within fluvio-deltaic Jurassic Elang and Plover formation sandstones (ConocoPhillips Exploration Australia Pty Ltd, 2008a). The Lynedoch 1 and 2 wells are located 6.5 km and 19.5 km to the east-northeast, respectively. The prospect is a large faulted structure on the eastern margin of the Sahul Platform. Barossa 1 reached a TD of 3435 mRT before it was sidetracked as Barossa 1 ST1 due to overpressuring, and reached a TD of 4310 mRT. Two drill stem tests were conducted over the Elang and Plover formations. The first test DST 1 over the interval 4000‑4148 mRT flowed gas at a rate of approximately 0.8 MMcfd (0.02 MMm3/d). The second test DST 2 over the interval 3946-3982 mRT flowed gas at a rate of approximately 30.1 MMcfd (0.85 MMm3/d). The gas contains high levels of carbon dioxide (16%) and has a low liquid content. Appraisal well Barossa 2, which was drilled in 2014, intersected 88 m of net pay across a 217 m interval in the Elang and Plover reservoirs (Santos, 2015). Pressure data suggest that the gas reservoirs penetrated at Barossa 2 and Barossa 1 are in hydraulic communication and share a common gas-water contact (MEO Australia, 2014d). Barossa 3 was completed in early 2015 and intersected 104 m of net pay across a total gas-bearing sandstone interval of 152 m within the Elang Formation and flowed gas at 27 MMcfd (0.77 MMm3/d) on test. Barossa 4 ST1 was spudded in January 2015 and further confirmed the Barossa field resources which are estimated to be 46 MMboe (Santos, 2015). Late Jurassic and Cretaceous shales provide an effective top seal to the Elang and Plover formations. Barossa 5 appraisal well is currently being drilled and a second well, Barossa 6, was spudded on 18 Arpil 2017 (ConocoPhillips, 2017; Sullivan, 2017). The Barossa field is a potential backfill option for the Darwin LNG plant as production from Bayu-Undan starts to diminish over the next decade (Garvey, 2015)

Infrastructure and markets

Release Area NT17-1 is proximal to the Barossa, Caldita, Evans Shoal, Evans Shoal South and Blackwood accumulations in Australian waters, and the Abadi gas accumulation in Indonesian waters. The Bayu‑Undan to Wickham Point gas pipeline is the closest fixed infrastructure.

Critical risks

Reservoir quality is variable due to localised diagenesis and irregularity of the natural fracture networks, which potentially reduce trap capacity and hydrocarbon recoverability. Intra-formational heterogeneity within the Plover Formation reservoir and source rocks is a risk. Where developed (e.g. at Sunrise 1), the distribution of shell interbeds play a primary role in vertical reservoir connectivity. Diagenetic variability in reservoirs is likely related to high geothermal gradients as measured at Evans Shoal 1 and Blackwood 1, which may preclude the generation and preservation of liquid hydrocarbons in deeper plays. Reservoir quality of the Frigate Shale and Elang Formation is likely to decrease basinward as more distal sediments become finer-grained. The complex rifting history and extensive faulting in the region increases the risk of trap breach. Gas flushing is pervasive in the northern Bonaparte Basin and is a major risk for the preservation of liquid hydrocarbons. Gas reservoired within the Plover Formation typically has a high carbon dioxide content.

NOPIMS data

Data relating to the Release Areas can be accessed through the National Offshore Petroleum Information Management System (NOPIMS), an online data discovery and delivery system for all Australian offshore petroleum wells and seismic surveys. http://www.ga.gov.au/nopims

Marine and Environment

Release Area NT17-1 characteristics

Release Area NT17-1 is located over pinnacle, slope, terrace and shelf geomorphic features in water depths of approximately 80−380 m, and is located 65 km north of Melville Island and 150 km northeast of the nearest mainland, the Cobourg Peninsula and Garig Gunak Barlu National Park.
No surface samples have been retrieved from the Release Area. However, Heap et al (2004) note that the outer shelf and upper shelf slope carbonate sediments are mixed with terrigenous clays from Indonesian rivers.
Potential hazards: pockmarks have been identified in shallow sediments in the nearby Petrel sub-basin (250 km southwest) and Malita Graben (75 km southwest) (Przeslawski et al, 2011; Nicholas et al, 2014), although such detailed surveys have not been undertaken within the Release Area. Tropical cyclones occur throughout the area during the monsoon season.

Commonwealth marine reserves

A portion of Release Area NT17-1 overlaps the Oceanic Shoals Commonwealth Marine Reserve.

Key ecological features

Key ecological features overlapping the area include the Shelf Break and Slope of the Arafura Shelf, and the carbonate bank and terrace system of the Van Diemen Rise (National Conservation Values Atlas, 2017).

Biologically important areas

Release Area NT17-1 overlaps a biologically important area for the Flatback Turtle, and a 80 km internesting buffer around nesting sites off Melville Island and Cobourg Peninsula (National Conservation Values Atlas, 2017http://www.environment.gov.au/webgis-framework/apps/ncva/ncva.jsf ).

There is also a known distribution area of the Pygmy Blue Whale which forages along the 200 m contour to the north of the Release Area (National Conservation Values Atlas, 2017 http://www.environment.gov.au/webgis-framework/apps/ncva/ncva.jsf).

The Atlas of Living Australia (www.ala.org.au) and the North-West Atlas (www.northwestatlas.org) provide further information on animals and plants recorded from the release area, including Threatened or Listed Species.

Heritage

No shipwrecks are listed in the area.

References and Information Resources

National Conservation Values Atlas http://www.environment.gov.au/webgis-framework/apps/ncva/ncva.jsf

Atlas of Living Australia http://www.ala.org.au/

North-West Atlas (www.northwestatlas.org)

Oceanic Shoals Commonwealth Marine Reserve https://www.environment.gov.au/topics/marine/marine-reserves/north/oceanic-shoals

Commonwealth Fisheries http://www.afma.gov.au/fisheries/

Northern Territory Fisheries https://nt.gov.au/marine/commercial-fishing/about-nt-commercial-fishing-industry

Shipwrecks http://www.environment.gov.au/heritage/historic-shipwrecks/australian-national-shipwreck-database

Geoscience Australia products

Regional geology and seismic

Line Drawings of AGSO – Geoscience Australia’s Regional Seismic Profiles, Offshore Northern and Northwestern Australian Geological Survey Organisation Record 2001/036 by Colwell and Kennard, 2001
Deep Structure of the Eastern Malita Graben and Adjacent Areas in the Timor and Western Arafura Seas, Survey 118 Operational Report by Hill and Ramsay, 1993.

Stratigraphy

Australia’s Basin Biozonation and Stratigraphy Chart Series: Bonaparte Basin Biozonation and Biostratigraphy Chart 33. Geoscience Australia Stratigraphy Chart by Kelman et al, 2014.
Characterisation of Natural Gases from West Australian Basins. Geoscience Australia by Boreham et al. 2000
Oils of Western Australia II. Geoscience Australia Report by Edwards and Zumberge
The Petroleum Systems of the Bonaparte Basin. Dataset by Earl, 2004
Source Rock Time-slice Maps, Offshore Northwest Australia. Petroleum data by West et al, 2004
Bonaparte Basin, Northern Territory (NT), Western Australia (WA), Territory of Ashmore and Cartier Islands Adjacent Area (AC), Joint Petroleum Development Area (JPDA). Cadman and Temple, 2004.
Quaternary Evolution, Modern Geological Processes and Potential Effects of Additional Petroleum Exploration Activity on the Van Diemen Rise, Timor Sea (East Malita Graben Area). AGSO report by Lavering, 1992.
Petroleum Prospectivity of the East Malita Graben Area, Bonaparte Basin. AGSO Report by West, 1992.
Light Hydrocarbon Geochemistry of the Bonaparte Basin, Including the Sahul Syncline, Malita Graben and Southern Petrel Sub-basin: Rig Seismic Survey 100: Project 121.22. Data package by Bishop et al, 1992.

Contact Geoscience Australia’s Client Services for more information or to order these reports or products,
phone 61 (0)2 6249 9966, email clientservices@ga.gov.au

References

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