contentsNew Shale Gas Results In The Amadeus And Georgina Basins
Lidena Carr, Geoscience Australia
Introduction
The Onshore Energy Security Program was funded by the Australian Government for five years (2006-2011) to provide geological information on frontier, onshore sedimentary basins in Australia, many of which are under-explored with respect to hydrocarbons.
Geoscience Australia Record 2011/10 Gas shale potential of the Amadeus and Georgina basins, Australia: preliminary insights was recently published as part of this program. This Record outlines work commissioned by Geoscience Australia and undertaken by GeoS4, Germany. It provides precompetitive information on the gas shale potential of the two basins, potentially leading to increased activity for hydrocarbon exploration.
Exploration in the Amadeus Basin began in the 1950s, eventually leading to the discovery of the Mereenie oil and gas field and the Palm Valley gas field.
Since that time, exploration has focused on Ordovician petroleum systems, with only minor exploration occurring in other parts of the basin succession. Older Neoproterozoic petroleum systems in the basin, including the Dingo-1 field, are inferred to be present outside the main areas of exploration.
Although the southern Georgina Basin is considered to have significant potential for hydrocarbons, it includes a largely unexplored Middle Cambrian petroleum system (Ambrose et al. 2001). Following the discovery of hydrocarbon indicators in water bores drilled into the Cambrian succession, exploration has included several petroleum exploration wells, which were unsuccessful. Before this study no work had been conducted on the prospectivity of shale gas in these areas.
For this study, 24 samples from the Amadeus and Georgina basins were provided by Geoscience Australia.
Eleven cuttings and core samples from the Amadeus Basin were collected from seven wells, including Dingo-1, Murphy-1, Orange-1, Mount Winter-2A, Tempe Vale-1, Tent Hill-1 and BMR Rodinga-6. These cuttings include samples from the Bitter Springs Formation (Late Neoproterozoic), Lower Giles Creek Dolomite (Middle Cambrian), Goyder Formation (Middle Cambrian) and the Horn Valley Siltstone (Early Ordovician). Thirteen core samples from the Georgina Basin were selected from the MacIntyre-1, Baldwin-1, BMR Mt Isa-1 and Elkedra-3 wells. All samples are of Middle Cambrian age, most of them being from the 'hot shale' of the Arthur Creek Formation.
Results
Amadeus Basin
Based on the samples analysed for this study, the Bitter Springs Formation, Lower Giles Creek Dolomite, and Goyder Formation are poor candidates for shale gas. Although they are characterised by high Production Indices (PI) ranging from 0.24-0.50 (wt ratio), a generally positive signal for overmature shale gas, the organic carbon (TOC) contents are very low (0.07- 0.16%), as are the remaining petroleum generating potentials (S2 yield is 0.08-0.21 µg/g sample). The free hydrocarbons, as well as the pyrolysis products, consist mainly of gases. A wide range of Tmax values (287-490 °C) reflects the broad and irregular shape of the S2 peaks, indicating that the samples are all overmature. The remaining gas yield potential of these samples is around 15 µg/g sample (Figure 1).
Of the three samples analysed from the Horn Valley Siltstone, two indicate the potential for shale gas because of their high TOC (3.16-3.42%), moderate production index (PI ~ 0.2) and Tmax of 445-449 °C (close to the minimum of 450 °C). These two samples can be classified as kerogen type II. Upon pyrolysis, they generate products signalling Paraffinic- Naphthenic-Aromatic Low Wax Oil potential, although their properties are very close to the boundary with the gas condensate field. The remaining gas-generating potential of the samples is 1775 and 2486 µg/g sample, respectively (Figure 1). The third sample from the Horn Valley Siltstone, appears inherently gas-prone and to contain adsorbed gas. It is leaner, with a remaining gas-generating potential of only 250 µg/g.
Georgina Basin
In the MacIntyre-1 well, two samples from the Arthur Creek Formation, have TOCs close to 1%, and Hydrogen Indices of 80 and 100 mg/g TOC, respectively. Two further samples from the Arthur Creek Formation have TOCs of 5.3-8.6%. The Hydrogen Index values of the latter samples are around 70 mg/g TOC. The Tmax values range from 457-475 °C for the four samples in this well, which denote ideal shale gas potential. Pyrolysis reveals that the first two samples from the Arthur Creek Formation are gas - and condensate-prone, with total remaining gas generation potential in each case of 300 µg/g. This latter potential yield is smaller, however, than the second two samples from the Arthur Creek Formation, whose remaining gas yields are 1230 and 3181 µg/g sample (Figure 1). Additionally, the free hydrocarbons in these two samples are paraffins below n-C20, thereby fulfilling an empirical prerequisite for gas shales.
Samples from the Baldwin 1 well, also from the Arthur Creek Formation, have TOCs of 5.47-11.0%, Hydrogen Index of 22-34 mg/g TOC and Tmax values of 522-586 °C. Their remaining petroleum potential is 660-1300 µg gas condensate /g (Figure 1).
Three samples from the BMR Mt Isa 1 drillhole, recovered from a 'Middle Cambrian Shale' were also analysed. They are all characterised by very low production indices (0.03-0.05 wt ratio). Two samples have high organic carbon contents (TOC = 9.0-16.0%) and high petroleumgenerating potential (HI ~ 600 mg/g TOC). They generate petroleum enriched in light hydrocarbons, even at low stages of thermal evolution. Remaining primary gas potential is very high, up to 8700-20000 µg/g sample (Figure 1). Based on that criteria, this source rock is worthy of serious consideration as a potential shale gas. The third sample is of lower quality (TOC = 0.5%, HI ~ 300 mg/g TOC) and was not analysed in any further detail.
Similar to samples from the Horn Valley Siltstone in the Amadeus Basin, samples from the NTGS Elkedra-3 drillhole, again from the Arthur Creek Formation, also fulfil the empirical criteria to be considered as shale gas candidates. They have high organic carbon content (TOC = 9.66-12.20%), Hydrogen Index (HI) values from 64-73 (mg/g TOC) and high Tmax values (467-474 °C). Upon pyrolysis, samples from the Arthur Creek Formation in the NTGS Elkedra-3 drillhole produce gas condensate. Their total gas potentials are 2500-3100 (µg/g sample).
Conclusion
This new information from these few samples increases our knowledge of the shale gas potential of the Amadeus and Georgina basins, which will contribute to decreased hydrocarbon exploration risk in these basins. Geoscience Australia Record 2011/10 Gas shale potential of the Amadeus and Georgina basins, Australia: preliminary insights, which contains the full analyses and preliminary interpretations, is available for free download from the Geoscience Australia website:
https://www.ga.gov.au/products/ servlet/controller?event=GEOCAT_ DETAILS&catno=71541
