Background Results and Discussion

Molecular profiles of the middle Cambrian
Arthur Creek Formation and Thorntonia Limestone,
southern Georgina Basin
E. Flannery1, T. Smith1, D.S. Edwards1, A. Andrews2 and C. Boreham1
1Geoscience
Australia, 2Environmental Isotopes Pty Ltd
Background
The Georgina Basin is a Neoproterozoic to Lower Devonian sedimentary basin
covering 325 000 km2 of western Queensland and the Northern Territory (Figure 1).
It is a northwest-southeast-trending extensional basin, with conventional and
unconventional hydrocarbon exploration targets in the southern depocentres within the
middle Cambrian Arthur Creek Formation (AC Fm). Recent biostratigraphic work using
agnostid trilobites [1] has determined that the prospective ‘hot shale’ (so called due to
high gamma-ray log values) at the base of the AC Fm in the Dulcie Syncline is older
(Templetonian) than the ‘hot shale’ in the Toko Syncline (Figure 2), which is of Floran
age. To complicate the stratigraphy further, the Thorntonia Limestone (Th Lst) in the
Undilla Sub-basin is also Templetonian in age, the same age as the AC Fm in the
Dulcie Syncline and younger than the Th Lst in the Dulcie Syncline (Ordian). In this
study molecular analyses of the AC Fm and the Th Lst from the CKAD0001 well were
undertaken in order to distinguish between the two formations and assist with future
correlations.
Figure 3: Comparison of n-alkane profiles (with data normalised to the n-alkane with the highest concentration in each sample)
between the lower Arthur Creek Formation and Thorntonia Limestone in the drill hole CKAD0001.
Figure 1: The Southern Georgina Basin showing petroleum titles and wells (CKAD0001 highlighted in red).
Results and Discussion
Fifteen source rocks from the AC Fm and the Th Lst in the CKAD0001 well were
chosen for Rock-Eval pyrolysis and hydrocarbon analyses using Gas Chromatography
Mass Spectrometry (GC-MS) (Table 1). The shales range in quality from poor to
excellent (lowest TOC 0.48% and highest 11.27 %) and span 44.75 m of core. Both
the AC Fm and the Th Lst share features with other lower Paleozoic source rocks and
oils, including a bias towards the low-molecular weight hydrocarbons [2]. Based on the
pristane/phytane ratio (Pr/Ph), all samples analysed fall within the suboxic range
(0.8> Pr/Ph <3) [3].
There are several features that distinguish the two formations.
• The n-alkane profiles differ significantly between the AC Fm and Th Lst (Figure 3),
in accordance with previous studies on the Elkedra-7A and Ross-1 wells [4]. Most
AC Fm source rocks show a unimodal distribution with no odd over even
predominance (OEP). Conversely 4 out of 5 Th Lst source rocks show a strong
OEP in n-C19 and all exhibit low Pr/n-C17 ratios (~0.1). These signatures indicate a
significant contribution from the prokaryotic organism G. prisca into the organic
matter in the Th Lst [6].
Figure 2: Stratigraphy of the southern Georgina Basin, including the Dulcie Syncline, Toko Syncline and Undilla Sub-basin.
Table 1: Samples used in this study, from the well CKAD0001 including total organic carbon (TOC) content (wt %), source
rock rating, Pr/Ph and Pr/n-C17. OEP= Odd over even predominance [8], *Poor= 0–0.5%, Fair 0.5-1%, Good 1-2% and Very
good 2–4%, Excellent >4% [9].
Formation
Depth (m)
TOC (wt. %)
Source Rock Rating*
OEP for n-C19
Pr/Ph
Pr/n-C17
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Arthur Creek Fm
Thorntonia Lst
Thorntonia Lst
Thorntonia Lst
Thorntonia Lst
Thorntonia Lst
525.09
535.6
536.5
537.6
539.12
540.19
540.6
540.8
541.1
541.3
572.45
573.02
573.39
573.65
573.84
2.75
5.79
3.59
8.01
9.39
8.74
10.42
6.60
11.27
5.89
0.64
1.85
1.88
3.12
0.48
Very Good
Excellent
Very Good
Excellent
Excellent
Excellent
Excellent
Excellent
Excellent
Excellent
Fair
Good
Good
Very Good
Poor
1.02
1.03
0.98
1.13
1.04
1.04
1.07
0.99
1.02
1.03
1.32
1.34
1.38
1.29
1.28
1.43
1.23
1.26
1.29
1.67
1.44
1.11
1.15
1.74
1.32
1.40
1.43
1.03
1.03
1.47
0.27
0.38
0.33
0.2
0.15
0.13
0.15
0.17
0.1
0.13
0.088
0.078
0.087
0.078
0.091
• In this study low concentrations of 2,3,6- trimethyl substituted aryl isoprenoids were
detected in AC Fm source rocks but not in Th Lst source rocks, in accord with
previous studies [2]. Generally, the predominant 2,3,6- trimethyl substituted aryl
isoprenoids in AC Fm source rocks are C17, and C18 and, to a lesser extent C19.
If derived from direct biosynthesis from green sulphur bacteria the presence of aryl
isoprenoids indicates photic zone anoxia [6 and 7].
• Average δ13Ccalcite values for the Th Lst (0.3 ‰ VPDB) and the AC Fm (1.9‰
VPDB) in the CKAD0001 well show that the Th Lst is isotopically depleted in 13C
relative to the AC Fm, with similar results being recorded for δ 13Cankerite, δ13Cdolomite
and δ13Csiderite.
Unfortunately the lower molecular weight bias and thermal degradation of the samples
precluded the comparison of the saturated biomarker distributions in the two
formations in this well. Further studies focusing on biomarkers as well as isotopic
profiles of the two formations in a range of wells will provide further assistance in
correlating these two formations over the southern Georgina Basin.
References
[1] Smith, T. E., Kelman, A., Laurie, J. R., Nicoll, R. S., Carr, L. K., Hall, L. & Edwards, D. 2013. An updated stratigraphic framework for the Georgina Basin, Northern Territory and Queensland. The APPEA Journal Conference and Proceedings, 53.
[2] Boreham, C. J. & Ambrose, G. J. 2007. Cambrian petroleum systems in the southern Georgina Basin, Northern Territory, Australia. In: Munson, T. J. & Ambrose, G. J. (eds.) Proceedings of the Central Australian Basins Symposium, Alice Springs, 16-18th August, 2005. Northern Territory Geological
Survey, Special Publication 2, 254-281.
[3] Peters, K. E. & Moldowan, J. M. 1993. The Biomarker Guide: interpreting molecular fossils in petroleum and ancient sediments, Englewood Cliffs, N. J., Prentice Hall.
[4] Volk, H., George, S. C., Kempton, R. H., Liu, K., Ahmed, M. & Ambrose, G. J. 2007. Petroleum migration in the Georgina Basin: Evidence from the geochemistry of oil inclusions and bitumens. In: Munson, T. J. & Ambrose, G. J. (eds.) Proceedings of the Central Australian Basins Symposium, Alice
Springs, 16–18th August, 2005. Northern Territory Geological Survey, Special Publication 2 (preliminary edition): 282-303.
[5] Anthony Hall P., McKirdy, D. M., Halverson, G. P., Jago, J. B. & Gehling, J. G. 2011. Biomarker and isotopic signatures of an early Cambrian Lagerstätte in the Stansbury Basin, South Australia. Organic Geochemistry, 42, 1324–1330.
[6] Summons, R. E. & Powell, T. G. 1987. Identification of aryl isoprenoids in source rocks and crude oils: Biological markers for the green sulphur bacteria. Geochimica et Cosmochimica Acta, 51, 557–566.
[7] Koopmans, M. P., Koster, J., van Kaam-Peters, H. M. E., Kenig, F., Schouten, S., Hartgers, W. A., De Leeuw, J. W. & Sinninghe Damste, J. S. 1996. Diagenetic and catagenetic products of isorenieratene: Molecular indicators for photic zone anoxia. Geochimica et Cosmochimica Acta, 60, 4467-4496.
[8] Scalan, E. S. & Smith, J. E. 1970. An improved measure of the odd-even predominance in the normal alkanes of sediment extracts and petroleum. Geochimica et Cosmochimica Acta, 34, 611–620.
[9] Peters, K. E. & Cassa, M. R. 1994. Applied source rock geochemistry. In: Magoon, L. B. & Dow, W. G. (eds.) The Petroleum System—From source to trap. Tulsa, Oklahoma: American Association of Petroleum Geologists Memoir 60.
GeoCat xxxxx
AOGC, Adelaide, December 2014
For Further Information: Dianne Edwards
Email: [email protected]
Ph: +61 2 6249 9782 Web: www.ga.gov.au