Area NT07-1

Troubadour Terrace, Bonaparte Basin

Petroleum Potential

Source rocks

The most important hydrocarbon source rocks in the Malita Graben and Calder Graben occur in the Plover Formation, which is also the most important reservoir target. This source/reservoir sequence was most recently discussed by Longley et al (2002) and Ambrose (2004 a, b) and also Edwards et al (2004). In the northern Bonaparte Basin, the oils reservoired in the Laminaria/Corallina fields are believed to be co-sourced from the Plover Formation (Edwards et al, 2004, George et al, 2004). The Elang Formation has also made some contribution, and is recognised as the dominant source at Bayu/Undan field. The relevant Plover Formation source rock in the northern Bonaparte Basin and in the Vulcan Sub-basin is a coastal plain/deltaic unit largely defined by the C. turbatus spore-pollen zone (viz, Unit C as defined in Ambrose, 2004a). The northern most well to intersect Unit C source rocks is in Thornton 1 drilled in the Joint Petroleum Development Area (JPDA). The Plover source rocks in the Greater Sunrise area may be slightly younger than the Unit C shales found to the west in the JPDA and Vulcan Sub-basin, but the interrelationship is not well understood.

Overall, the Plover Formation contains fair to good oil- and gas-prone source rocks across the Sahul Platform, and moderately wet-gas source rocks on the Troubadour Terrace. Elsewhere in the northern Bonaparte Basin the Plover Formation is mainly a source of dry gas. Unit C source rocks are speculated to occur in the deeper Plover Formation section in the Malita and Calder graben (Ambrose, 2004a).

Development of syn-rift Callovian–Oxfordian shale sequences (the Elang or Laminaria Formation), which are proven source rocks elsewhere in the Bonaparte Basin, remains speculative in the Malita Graben, as is the source potential of the Oxfordian–Kimmeridgian Cleia Formation. Organic-rich shales of the Late Jurassic–Early Cretaceous Flamingo Formation have been intersected in exploration wells in the region and are potential sources of hydrocarbons. The best section occurs in Heron 1, which tested an inversion structure in the Malita Graben and encountered 885 m of Flamingo Formation shales. Total organic carbon (TOC) contents ranges between 0.2 and 10%, but hydrogen indices (HI) indicate the sequence is gas-prone. The overlying Bathurst Island Group shows fair TOC contents ranging from 0.1 to 2.9%, and, with the exception of the basal unit (the Echuca Shoals Formation), the sequence appears to be gas-prone, although there is some potential for mixed oil/gas-sourcing (West and Passmore, 1994). The Flamingo Formation is also a secondary target reservoir in this region. Core derived porosities range from 9% in the basin centre to 30% in basin margin locations (Botten and Wulff, 1990).

Gas composition

Recent geochemical studies indicate the Greater Sunrise gas field was sourced locally from the Plover Formation on the Malita Graben and Troubadour Terrace (Longley et al, 2002). Further east, dry gas has been discovered in the Plover Formation at Evans Shoal 1, 2, Evans Shoal South 1 and Barossa 1, ST1. A tight gas column is recorded in Lynedoch 1, 2. Gas was also discovered in the Plover Formation by the Abadi 1 and Caldita 1 exploration wells, the former being located in Indonesian waters. The carbon isotopic (?13C) compositions of the liquids recovered from these gas fields are overall similar to those of the Greater Sunrise area, indicating derivation from the same source rock package (Figure 9; Edwards and Zumberge, 2005). However, variations in the isotopic composition between gases, and between the gas and condensate range n-alkanes (AGSO and Geotech, 2002) imply that some of the accumulations comprise mixtures of differing thermal maturity and not all of the gases are generated by the same source unit

The gases tested at Evans Shoal 1 and 2 have high carbon dioxide contents (18% at 3554 mKB and 24% at 3633 mKB, respectively; http://dbforms.ga.gov.au/www/npm.well.search) resulting in the early assessment of possible methanol production from this field. Similarly high concentrations of carbon dioxide are recorded at Chuditch 1 (20% at 2934 mKB), although lower concentrations of carbon dioxide are recorded at Sunrise (4%) and Abadi (9%; Yui, 2003).


[back to top]

Reservoir rocks

The upper Plover Formation is the main target reservoir and its facies development and palaeogeography are shown in Figure 10 (Barber et al, 2004). This unit is tight in basinal areas, but reservoir quality improves markedly away from the main depocentres. Excellent gas flow rates of 25, 30 and 33 MMscf/d have been recorded from the Plover Formation in the Evans Shoal 2, Barossa 1 and Caldita 1 exploration wells, respectively. Depth of burial has a significant impact on the degree of diagenesis, and reservoir quality is deemed most favourable where the depth of burial has been less than 3000 m, in which case present day porosities are estimated between 15 and 30% (NTGS, 1990). Botten and Wulff (1990) speculated that the Plover Formation would also provide potential plays at depths greater than 3300 m, where early hydrocarbon emplacement has inhibited diagenesis. This is the case at Evans Shoal (near top reservoir approx 3600 m SS) and Caldita 1 (near top reservoir approx. 4000 m SS). Significantly, it remains uncertain why the Plover reservoirs at Lynedoch were tight, given that they occur at approximately the same structural elevation as Caldita 1, which is located about 20 km to the south. Plover Formation reservoirs in Abadi 1 (3850 m) flowed gas at 25 MMscf/d suggesting regional development of viable reservoirs.

Evans Shoal 2 encountered more than 360 m of Plover Formation sandstone containing high-permeability streaks (Lowe-Young et al, 2004; Figure 8). Pressure data indicates that the Evans Shoal structure is filled to spill, with a closure height of 300 m. Estimated reserves are 6.6 TCF of sales gas (NTDPIFM, 2006). Depositional facies interpretation indicates the presence of marine shoreface sandstones in the upper Plover Formation, which form the primary reservoir zone. The lower Plover Formation section is mainly a fluvial–estuarine facies with different reservoir properties. Production tests over two zones resulted in gas flows of 25.5 and 5.5 MMscf/d, with the larger flow mainly sourced from the upper shoreface zone. Natural fractures observed in core samples have probably enhanced reservoir performance.

Quartz clastics within the overlying Flamingo Formation offer good reservoir targets with the opportunity for combination structural/stratigraphic plays. The Flamingo Formation clastics were deposited on a marine shelf and in possible low-stand turbidite fan complexes (Barber et al, 2004). Figure 11, based on the work of Barber et al (2004), portrays the palaeogeography of the Flamingo Group showing the areas of likely reservoir development.

Seals

The regional seal for the Plover/Flamingo reservoirs is the thick claystone unit of the lower Bathurst Island Group. This group also contains high-quality reservoirs, including regionally developed Santonian and Maastrichtian sandstones. The thickness of the Maastrichtian sandstones ranges from 158 m in Heron 1 to 583 m in Lynedoch 1; these are the equivalent of the oil-bearing Puffin Formation sandstones tested in the Vulcan Sub-basin further to the west.

West and Passmore (1994) suggested that Maastrichtian sandstones in Heron 1 and Evans Shoal 1 represented turbidite flows deposited as basin floor fans, tapping up-dip coastal plain and shelfal sands during a low sea level stand. On seismic lines, these sandstones appear as widespread, hummocky clinoform reflections with possible mounding and foresetting (West and Miyazaki, 1994). The porosity in these sandstones ranges from 10 to 33%, but the presence of seal and hydrocarbon charge remain to be proved.


[back to top]

Trap formation and timing of hydrocarbon generation

The highly faulted Greater Sunrise structure was formed in the Miocene or Pleistocene and was filled to spill at about 10 Ma or less (Seggie et al, 2000). Whereas, the structuring at Evans Shoal and Lynedoch appears to be much older (pre-Turonian) than that of the Sunrise complex, being associated with the formation of the Malita Graben and the juxtaposition of rift-related terraces and tilted fault blocks in the Tithonian

Modelling by West and Miyazaki (1994) suggests that gas generation from the Plover Formation at Evans Shoal 1 (Figure 12), and from the surrounding faulted terraces, probably commenced in the Mid–Late Cenozoic. In the Malita Graben depocentre, gas generation from the Plover Formation commenced in the Middle Cretaceous and continues to the present day.

Modelling by West and Miyazaki (1994) at Heron 1 in the Malita Graben indicates that the Flamingo Formation and lowermost Bathurst Island Group entered the gas window in the Late Cretaceous to Paleogene (Figure 13). Oil-prone source rocks of the lower Bathurst Island Group are in the oil window or have passed through it since the Eocene, therefore opportunities for oil retention exist in migration shadow zones on the faulted margins of the Malita and Calder Graben. It is significant that liquid petroleum-related fluorescence anomalies detected by airborne laser Fluorosensor (ALF) occur south and east of the Calder Graben, hinting at the generation of liquid hydrocarbons in this depocentre (Martin and Cawley, 1991). However, gas flushing is pervasive through this region and is a major risk for the preservation of liquid hydrocarbons.

Play types

The known gas fields in the northeastern Bonaparte Basin are large faulted anticlinal structures at the base of the regional seal (Longley et al, 2002). Hence, tilted fault blocks, faulted anticlines and broad, low relief anticlinal drape over tilted fault blocks provide the main structural plays in this region. In the release area tilted horst blocks are attractive targets on faulted terraces adjacent to the Malita and Calder graben. The possibility of hanging wall fault traps on the down-thrown side of the bounding faults provides a secondary play type.

A regional limestone unit of Aptian–Albian age (the Darwin Formation radiolarite), occurs in the lower part of the Bathurst Island Group. Significant gas shows were reported from fractures in Lynedoch 1 and minor shows were reported in Heron 1 and Evans Shoal 1 from the same section. The play is speculative, but if fracture porosity is widespread, this section could hold some commercial interest.

In summary, the release area offers excellent prospectivity for gas, with giant gas accumulations occurring immediately to the north, south and west. Liquids contents are likely to be low and probably range between 10 and 30 bbls/MMscf. There is some potential for increased liquids contents, but oil is a high risk target in this region due to widespread gas flushing given the discovery of the numerous dry to moderately wet-gas fields in the region.


[back to top]