Accumulation and mixing of hydrocarbons in oil fields along the Murteree Ridge, Eromanga Basin, South Australia

Organic Geochemistry Organic Geochemistry 35 (2004) 1597–1618 www.elsevier.com/locate/orggeochem

Accumulation and mixing of hydrocarbons in oil fields along the Murteree Ridge, Eromanga Basin, South Australia Khaled R. Arouri a,*,1, David M. McKirdy a, Lorenz Schwark b, Detlev Leythaeuser b, Peter J. Boult c a

Organic Geochemistry in Basin Analysis Group, Geology and Geophysics, School of Earth and Environmental Sciences, University of Adelaide, Adelaide, SA 5005, Australia b Geological Institute, University of Cologne, Zu¨lpicherstrasse 49a, 50674 Cologne, Germany c Petroleum Group, Office of Minerals and Energy Resources, PIRSA, GPO Box 1671, Adelaide, SA 5001, Australia Received 12 September 2003; accepted 5 May 2004 (returned to author for revision 12 April 2004) Available online 19 August 2004

Abstract The Murteree Ridge is a focus for up-dip migration from two major hydrocarbon kitchens within the intracratonic Cooper (Carboniferous–Triassic) and Eromanga (Jurassic–Cretaceous) Basins of South Australia. The accumulation histories of nine oil fields along and adjacent to the ridge have been reconstructed by sequential solvent extraction and analysis of residual oils in sandstone core plugs from their stacked reservoirs. Four Cretaceous reservoir units received multiple oil charges that varied widely in source affinity, from mostly Jurassic (and/or Cretaceous) to overwhelmingly Permian in origin. The distributions of residual oil saturations in live and palaeo-columns are consistent with the existence of two compartments, with the uppermost pools (Cadna-owie, Murta) showing the highest Permian inputs. These accumulations represent the earliest escape of low-maturity Cooper-sourced oil into overlying Eromanga strata. This initial charge was displaced upwards into the shallower traps by subsequent hydrocarbon pulses. Three separate Permian-charge episodes can be recognised. The corresponding DST oils (0.6–0.7% Rc) represent either the compositional average of all charges to their respective reservoirs, or a continuation of the alternating filling pattern observed for successive charges. Oils in the Hutton (Jurassic) reservoir of the outlying Kerrina and Mudlalee Fields to the northeast appear to be mixtures of two distinct Early Permian oil families, variably co-mingled with locally derived Jurassic and possibly Cambrian hydrocarbons. Ó 2004 Elsevier Ltd. All rights reserved.

1. Introduction

*

Corresponding author. Fax: +971 3 7671291. E-mail addresses: [email protected], k.arouri@ uaeu.ac.ae (K.R. Arouri). 1 Present address: Department of Geology, United Arab Emirates University, PO Box 17551, Al-Ain, United Arab Emirates. Fax: +971 3 7671291.

For any oil field, better understanding of petroleum migration and in-reservoir mixing requires recognition of the filling sequence of the pore network by its respective hydrocarbon charges, as well as the direction and timing of fluid movement (England et al., 1995, and references therein). This is especially true of fields with stacked reservoirs and multiple source rocks (e.g.

0146-6380/$ - see front matter Ó 2004 Elsevier Ltd. All rights reserved. doi:10.1016/j.orggeochem.2004.04.008

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Leythaeuser et al., 1988; Leythaeuser and Ru¨ckheim, 1989). In his review of the process of hydrocarbon accumulation, England (1994) found that during trap filling (usually rapid on a geological time scale) extensive mixing is impossible due to poor reservoir-wide connectivity. However, diffusion and convection can over time eliminate much of the compositional gradients inherited from directional charge. Although diffusion may mix an oil column at a single location, this process is too slow to cause lateral mixing across an oil field. Furthermore, according to England (1994), thermal convection is ineffective in mixing oil pools without gas caps; and partially sealing faults and intra-formational seals may slow convection driven by density differences. It is therefore reasonable to assume that individual oil charges, which have filled a trap over an extended period of geological time, can be retrieved separately from reservoirs or carrier beds. Among the several investigative approaches to the related issues of petroleum migration and in-reservoir mixing are conventional oil-source correlation (e.g. Michaelsen and McKirdy, 2001), fluid inclusions (e.g. Karlsen et al., 1993), kinetic and numerical modelling (e.g. Forbes et al., 1991) and microscopic analyses (Rasmussen, 1997). Schwark et al. (1997) developed a technique for the sequential solvent flow-through extraction (SFTE) of various oil phases present in reservoir core plugs, thereby enabling different oil charges to be individually identified and the filling history reconstructed. This analytical approach is based on the assumptions that (1) oil movement in the pore system of a carrier bed (or reservoir) never occurs without leaving traces along the transport path (e.g. England, 1994); and (2) the oil which entered the reservoir last is the first to be extracted with SFTE, while the initial charge will be recovered last. A minimum of two phases can be retrieved from a reservoir or carrier rock, namely (1) a mobile (free or producible) oil; and (2) an adsorbed (or residual) oil rich in NSO compounds. An oil charge that re-migrated or was displaced from a reservoir/carrier bed by later charges can be expected to leave behind an NSO-rich oil phase adsorbed on to the mineral surfaces of the pore walls. Subsequent hydrocarbon charges will have lower proportions of their NSO content preferentially removed, resulting in Ôoil zoningÕ or Ôonionskin-likeÕ layering in reservoirs with multiple charges. ÔAdsorbed oilsÕ represent early hydrocarbon charges entering the reservoir, while Ôfree oilsÕ typically correspond to final charges. Residual oils are generally different from production (or DST) oils (Larter and Aplin, 1995), especially if the reservoir received multiple hydrocarbon charges. The former are typically low in aliphatics and rich in asphaltenes and resins compared to the free oil (Schwark et al., 1997). Free oil, on the other hand, is similar to DST oil as both most likely represent the same hydrocarbon charge. Free and adsorbed oils

are expected to be equally mature if the reservoir received a single hydrocarbon charge, or if charges from different source kitchens just happen to be of equal maturity. However, in reservoirs with multiple charging episodes, more mature DST and free oils can be expected where the same source unit continued to supply the trap with petroleum of progressively higher maturity (e.g. Brooks et al., 1987; see also Schwark et al., 1997). The reverse situation (i.e. final charges with maturities lower than that of initial charges) can occur in petroleum systems with multiple sources and charging histories (Karlsen et al., 1995). Notwithstanding the considerable efforts already made to unravel the origin and degree of in-reservoir mixing of oils in the Cooper and Eromanga Basins, the question of which organic-rich rocks are their source(s) is still largely a matter of debate. Conventional oil-source rock correlations based on source- and maturity-specific biomarkers are of limited use due to similarities in the fluvio-deltaic, paludal and lacustrine source rock facies of both basins. Jenkins (1989), for example, used the relative abundances of 25,28,30-trisnorhopane and 19-norisopimarane in oils and estimated an average of 20% Eromanga input across the basinÕs oil accumulations. However, this approach was questioned by Tupper and Burckhardt (1990), Michaelsen and McKirdy (1996), and Alexander et al. (1996) as these biomarkers are not specific to the Eromanga Basin. Aromatic hydrocarbon biomarkers have been found to be more reliable in distinguishing Eromanga from Cooper oils. This was first realised by Alexander et al. (1988) who devised a method based on conifer-derived araucariacean (postTriassic) aromatic hydrocarbon biomarkers to distinguish Permian (Cooper)- and Jurassic (Eromanga)-derived hydrocarbons. Nevertheless, such qualitative approaches are expected to overestimate the Eromanga contributions to mixed oils as these are commonly more enriched than Cooper oils in high-molecular-weight hydrocarbons, including the araucariacean biomarkers: 1,2,5-trimethylnaphthalene, 1-methylphenanthrene, 1,7dimethylphenanthrene and retene. Based on the assumption that mixing in the Eromanga Basin would commonly occur between Permian condensates and less mature waxy Jurassic oil, Alexander et al. (1996) offered a solution to this problem by comparing the maturities of the light- and heavy-end aromatic compounds in the same oil sample: where the two maturities differ, the oil is inferred to be of mixed origin. Estimates of mixing ratios based on carbon isotopic compositions of individual n-alkanes in oils (Boreham and Summons, 1999) are expensive and at best semi-quantitative. A unique combination of methylphenanthrene parameters offers a convenient and rapid means of quantitatively assessing the degree of mixing of Cooper and Eromanga oils (Michaelsen and McKirdy, 1999, 2001). This Ômixing modelÕ is based on a cross-plot of 1-methylphenan-

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

threne/9-methylphenanthrene (an araucariacean sourcerelated parameter: Alexander et al., 1988) against 2methylphenanthrene/1-methylphenanthrene (a maturity parameter: Radke et al., 1982). This plot was used by Michaelsen and McKirdy (1999) to define different mixing trends in the Queensland and South Australian sectors of the Cooper and Eromanga Basins (Fig. 3). Determinations of mixing ratios along these trends were performed (Michaelsen, 2002) by comparison with a computer-generated mixing curve for hypothetical mixtures of end-member oils, viz. those recovered from the Permian Tirrawarra Sandstone and the Jurassic Birkhead Formation in the Moorari oilfield. In this paper we present our findings on the accumulation history and mixing of petroleum fluids in fields along (and adjacent to) the Murteree Ridge (Figs. 1(a)–(c)). These findings are based mainly on the methylphenanthrene distributions of representative residual oils recovered from core plugs of Cretaceous sandstones using the SFTE cell (Schwark et al., 1997). DST oils from the same Cretaceous and underlying Jurassic reservoir units were also analysed for comparison, together with representative local source rocks. Finally, estimates of mixing ratios derived from Michaelsen and McKirdyÕs model curves were compared with those obtained using a new curve based on the actual analysis of artificial mixtures of the same two end-member Cooper and Eromanga oils (Arouri and McKirdy, 2004).

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2. Geological background 2.1. Tectonic setting The entirely non-marine Late Carboniferous–Triassic Cooper Basin is an intra-cratonic depocentre underlain by the Cambro-Ordovician Warburton Basin that in turn rests on Proterozoic basement. Basin-wide compression during the Late Triassic resulted in three major depressions, namely the Patchawarra, Nappamerri, and Tenappera Troughs in the South Australian (SA) sector of the basin. These are separated by northeast-trending structural highs: the Gidgealpa–Merrimelia–Innamincka (GMI) Ridge to the north, and the contiguous Murteree and Nappacoongee Ridges to the south (Gravestock and Jensen-Schmidt, 1998). Crustal sagging that started in the Early Jurassic led to deposition of the non-marine and later marine sediments of the Eromanga Basin (Jurassic–Cretaceous).

2.2. Burial and thermal history Cumulative evidence from thermal modelling based on vitrinite reflectance, apatite fission track annealing (AFTA) and argon dating (Moussavi-Harami, 1996; Tingate and Duddy, 1996; Deighton and Hill, 1998,

(a) Fig. 1. (a) Map of the study area showing the location of the Murteree Ridge on the southwestern margin of the Cooper Basin, and wells sampled for residual and DST oils and source rocks. (b) Generalised stratigraphic column of the Cooper and Eromanga Basins. Highlighted are the various petroleum system elements and processes. The major expulsion events are after Deighton and Hill (1998). (c) Seismic section across the Murteree Ridge showing truncation of Permian strata by Mesozoic erosion and locations of fields sampled for this study. The line of section is shown in (a).

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Fig. 1b (continued)

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

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Fig. 1c (continued)

and references therein) points to multiple oil expulsion episodes in the Cooper/Eromanga Basins. It appears that hydrocarbons were generated as a result of four main heatflow events: in the Late Permian (250 Ma), late Early Cretaceous (105 Ma), Late Cretaceous (90 Ma) and late Tertiary–present (5–0 Ma). The Late Cretaceous event was probably the ‘‘critical moment’’ that resulted in maximum expulsion from both the Permian and Jurassic source rocks in response to a combination of high heatflow and maximum burial (Fig. 1(b)). Other events generated only minor amounts of hydrocarbons, the earliest of which (Late Permian) is restricted to the Patchawarra Formation in the Nappamerri Trough due to its rapid subsidence, possibly associated with increased heatflow. Oil produced in the first expulsion event can have been trapped only in the Cooper Basin sequence – as this event predated deposition of the Eromanga sequence – unless remobilised later by restructuring and fault reactivation (Fig. 1(b)).

The Cooper-sourced and reservoired system can be divided into two subsystems depending on whether their hydrocarbons are derived from the Early Permian Patchawarra Formation or the Late Permian Toolachee Formation. These two sources are distinguishable by their different n-alkane C-isotopic profiles (Boreham and Summons, 1999). Likewise, the Eromanga system can be subdivided into the Birkhead Petroleum System (Middle-Late Jurassic) and the Murta Petroleum System (Early Cretaceous), reflecting their respective sources. The oils of both these systems are characterised by nearly flat n-alkane C-isotopic profiles (Boreham and Summons, 1999). The extent to which the Early Jurassic Poolowanna Formation and pre-Permian (probably Cambrian) source rocks contributed to different oil accumulations is yet to be fully investigated. Of the known hydrocarbon sources (Fig. 1(b)), the Patchawarra and Birkhead Formations are the two most prolific, accounting for the bulk of the cumulative petroleum resources of the Cooper and Eromanga basins.

2.3. Petroleum systems 2.4. Reservoir and seal rocks Exploration activities in the SA sector of the Cooper/ Eromanga Basin since 1960 have resulted in the discovery of 70 oil fields – the majority in Eromanga reservoirs – and 124 gas fields (Morton, 1996; Laws and Gravestock, 1998). These hydrocarbon occurrences belong to three main petroleum systems: (1) Cooper-sourced and reservoired, (2) Cooper-sourced/Eromanga-reservoired, and (3) Eromanga-sourced and reservoired (Boreham and Summons, 1999; Michaelsen and McKirdy, 2001).

Hydrocarbon discoveries have a wide stratigraphic distribution in the Cooper/Eromanga province, spanning almost the entire succession of both basins (Fig. 1(b)). The main producing reservoirs are the fluvial sands of the Patchawarra Formation and Hutton Sandstone, with the Birkhead and Poolowanna formations hosting smaller oil pools (Gravestock et al., 1998a,b). Other important reservoirs include the Tirrawarra

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Sandstone and Toolachee Formation (Permian), Namur Sandstone (Jurassic–Cretaceous) and the Murta Formation and its McKinlay Member (Cretaceous). The aforementioned hydrocarbon accumulations are trapped by either regional or intraformational seals, the stratigraphic levels of which are highlighted in Fig. 1(b). Regional seals within the Cooper Basin are the Permian Murteree and Roseneath shales and the Triassic Arrabury Formation (in the Nappamerri Group), while in the Eromanga Basin these are mainly carbonaceous shales of the Middle Jurassic Birkhead Formation and the Early Cretaceous Murta Formation and Bulldog Shale. Fine-grained carbonaceous (and in some instances coaly) lithofacies within the different reservoirs are relatively widespread and form effective intraformational seals that in fact cap the majority of the Cooper BasinÕs oil and gas fields (Gravestock et al., 1998a,b). Where regional seals pinch out on ridges or towards the basin margin, or intraformational traps are filled to the spill point, stacked hydrocarbon pools can be expected (Heath et al., 1989; Boult et al., 1998; Gravestock et al., 1998a,b). Mixing of Permian oil with younger hydrocarbons could have also been facilitated where the sealÕs efficiency was inadequate to retain the hydrocarbon column until its structural spill point was reached (Boult et al., 1998; Gravestock et al., 1998a,b). Jurassic–Cretaceous structuring and drapes over old structures are evident in seismic sections (e.g. Fig. 1(c)), together with Late Cretaceous–Tertiary structural re-activation. The Murteree Ridge is a broad, flat-topped, northeast-trending horst from which the entire Cooper Basin sequence was eroded during Late Triassic, and where Early Jurassic strata of the Eromanga Basin rest unconformably upon the basement (Fig. 1(c)). It separates two major hydrocarbon kitchens, the Nappamerri Trough to the north and the Tenappera Trough to the south (Fig. 1(a)), and represents a major structural focus for up-dip hydrocarbon migration from these two troughs. Given the multiple source rocks, stacked reservoirs, seals of different extents and efficiencies, and somewhat complex burial and thermal history of the Cooper and Eromanga basins (Fig. 1(b)), it is highly likely that their reservoirs received multiple hydrocarbon charges.

3. Samples and analytical methods Following a comprehensive interrogation of wellcompletion reports and the petroleum database (PEPS) of Primary Industries and Resources South Australia (PIRSA), five oil fields (Biala, Jena, Limestone Creek, Nungeroo and Ulandi) along the Murteree Ridge (Figs. 1(a) and (b)) were sampled for residual oil analysis according to core availability (Table 1). Preference was given to boreholes with multiple reservoirs, and particu-

lar attention was paid to DST oils with different API gravities. Sandstones with excellent reservoir quality (high permeability, porosity, oil saturation, and fluorescence) were the prime targets for residual oil (sandstone plug) samples. Reservoir units sampled are the Murta Formation and its McKinlay Member, and the Namur Sandstone (Fig. 1(b)). DST oils were selected primarily from the same intervals from which plugs were taken for residual oil analysis. Other DST oils from the nearby Alwyn Field, as well as from the outlying Mudlalee-3, Kerinna-1, and Kobari-1 wells, were also sampled (total n = 26), ensuring optimal areal and stratigraphic coverage of the study area (Fig. 1(a)). Table 1 summarises the sample details and includes relevant core data. Twelve core plugs from representative Cretaceous reservoir (and/or carrier bed) cores were cut and their residual oils sequentially extracted according to the procedure of Schwark et al. (1997), but with a modified solvent system. Dichloromethane (DCM) was used as the first solvent, and a 50:50 mixture of methanol and chloroform as the second solvent. Extraction with the latter was started when colour was no longer observed in the DCM extracts. Individual extracts, each collected for 30 min, were then rotary-evaporated, air-dried and weighed. The DCM extracts are numbered sequentially (1, 2, 3, . . .) and the methanol–chloroform extracts follow with a new sequential numbering plus the letter ‘‘a’’ (i.e. 1a, 2a, 3a, . . .). Thin-layer chromatography-FID analysis of all SFTE extracts (n = 152) was carried out using an IATROSCAN instrument (Karlsen and Larter, 1991) to determine compound class distributions. Those SFTE fractions selected for subsequent analyses, and all the DST oils, were fractionated by MPLC into aliphatic hydrocarbons, aromatic hydrocarbons and polar compounds (Radke et al., 1982). The aromatic fractions were analysed by gas chromatography-mass spectrometry (GC-MS) in SIM mode using a HP 6890 GC interfaced to a HP MSD 5973 and controlled by Chemstation software. The methylphenanthrene index (MPI-1) was measured and the vitrinite reflectance of the source rock at time of expulsion (%Rc) calculated using the calibration of Radke and Welte (1983). The two methylphenanthrene ratios (1-MP/9-MP and 2MP/1-MP) were measured for plotting on Michaelsen and McKirdyÕs (1999, 2001) mixing diagram (Fig. 3). The same ratios were also measured in the two (Permian and Jurassic) end-member oils and nine of their mixtures in order to create a ‘‘standard’’ curve (= manual mixingÕ curve in Fig. 3(a): Arouri and McKirdy, 2004). The latter was used for the calculation of mixing ratios, and for re-evaluation of Michaelsen and McKirdyÕs mixing trends discussed above. SFTE samples analysed by MPLC and GC-MS from each core plug comprised a minimum of two extracts (usually fractions 2 and 2a, representing late and early

Table 1 Sample details, including analytical data (compiled from well-completion reports and PEPS database) for residual oil core plugs, DST oils and source rocks from fields along and adjacent to the Murteree Ridge Sample

Field

Number

Well

Formation

5

Biala

7

Actual depth tested Biala-7 Jena-6

10

Jena

12

Jena-11

13 16 18 19 20

Limestone Creek

Limestone Creek-9

Nungeroo

Nungeroo-1

21 22 DST oil samples

Ulandi

1 2 3

7 8

Biala

13 14

Jena

15 17

Kerinna

1,237.31

1,237.31

50

22.3

47.6

67.4

32.6

19.8

90% moderately bright yellow-green

1,242.49

1,242.49

289

18.9

44.1

58.8

41.2

14.7

100% moderately bright yellow-green

Murta

1,191.21

1,191.21

7.4

18.7

45.2

60.2

39.8

15.0

fair-good

Murta

1,183.16

1,183.16

63

22.2

47.1

56.1

43.9

9.0

100% glowing yellow-white-green

McKinlay

1,223.95

1,223.95

154

25.6

48.8

64.1

35.9

15.3

100% glowing yellow-white

Namur

1,236.62

1,236.62

1938

61.7

38.3

7.6

Oil Exploration (McKinlay) well Oil Development/Appraisal Block Oil Development/Producing (McKinlay) well

50% dim-mod. bright yellow-green

25.5

54.1

McKinlay

1,242.97

1,242.97

11

22.3

31.8

52.2

47.8

20.4

dull yellow

Namur

1,254.43

1,254.43

1718

29.1

9.2

33.3

66.7

24.1

trace very dull yellow, trace residue

topmost Namur

1,262.79

1,263.35

334

23.7

42.9

76.6

23.4

33.7

100% bright yellow, seeping oil

Development well Oil Exploration (Namur) well

227

20.7

28.1

63.8

36.2

35.7

ditto

927

24.3

30.9

64.9

35.1

34.0

100% bright yellow-green, seeping oil

Wildcat Exploration (Producing Namur; Suspended Murta)

Ulandi-2

Murta

1,200.09

1,200.09

28

26.2

42.6

60.5 39.5 Oil recovery

17.9

100% pale yellow/white

Oil Appraisal/Production well (Murta)

Biala-3

Jena-12 Jena-2

16

McKinlay Namur

1,244.65

Jena-11

12

Fluorescence

loss (%)*

1,266.93

Biala-7

11

Well status

Petroleum Water

1,244.96

Biala-6

10

Saturation (%) Residual oil Original oil

1,267.05

Biala-1

9

(%)

Namur

Alwyn-5

6

Ka (mD)

Namur

Alwyn-3

5

Porosity

Ulandi-1

Alwyn

4

Permeability

McKinlay

DST 1 (1,230.17-1,236.27)

NFTS. Rec. 28 bbls oil

Murta

DST 2 (1,191.77-1,201.52)

NFTS. Rec. 12 bbls oil

McKinlay

DST 1

Namur

DST 4

Cadna-owie/Murta

DST 1 (1,189.94-1,216.15)

NFTS. Rec. 15.5 bbls oil (42.2 API)

Murta/McKinlay

DST 2 (1,227.13-1,242.37)

NFTS. Rec. 19.2 bbls oil (40.5 API)

Murta/McKinlay

DST 1 (1,232.31-1,236.27)

NFTS. Rec. 15.2 bbls oil (40.4 API)

Murta/McKinlay

DST 1 (1,234.75-1,239.93)

NFTS. Rec. 15 bbls oil

Murta

DST 3 (1,187.50-1,206.40)

NFTS. Rec. 0.7 bbls oil

Murta/McKinlay/Namur DST 1 (1,233.22-1,242.97)

OTS, Q=190 BOPD. Rec. 46.5 bbls oil

McKinlay

DST 1 (1,217.98-1,230.78)

NFTS. Rec. 48 bbls oil (41 API)

Cadna-owie/Murta

DST 3 (1,173.48-1,193.60)

NFTS. Rec. 6.3 bbls oil (42 API)

Cadna-owie/Murta

DST 2 (1,181.41-1,221.03)

NFTS. Rec. 12.8 bbls oil (41.5 API)

Cadna-owie/Murta

DST 3 (1,196.04-1,205.79)

NFTS. Rec. 0.75 bbls oil. Water also produced.

Murta/McKinlay

DST 1 (1,225.30-1,229.56)

NFTS, Rec. 25 bbls oil (43 API) NFTS, Rec. 11.4 bbls oil (42 API)

Murta

DST 2 (1,184.45-1,211.58)

Kerinna-1

Hutton

DST 3

Kobari-1

Murta

DST 1

Oil Appraisal well (Murta/McKinlay)

Oil Exploration (Murta-McKinlay) well Oil Exploration (Murta-McKinlay) well Oil Exploration (McKinlay) well Oil Exploration (McKinlay) well Block Oil Development/Producing (McKinlay) well Block Oil Development well Oil Appraisal well (Murta/McKinlay)

18

Kobari

19

Limestone Creek

NFTS, trace oil, Rec. 35 bbls oil (42.5 API)

Development well

20

Mudlalee

Mudlalee-3

Hutton

DST 1

21

Nungeroo

Nungeroo-1

Murta/Namur

DST 2 (1,260.96-1,278.33)

OTS, Q=35 BOPD (41.3 API), Rec. 3.7 bbls oil

Oil Exploration well (Namur)

Cadna-owie/Murta

DST 1 (1,191.16-1,212.49)

NFTS, Rec. 14.1 bbls (41.7 API oil)

Namur

DST 2 (1,236.88-1,241.45)

NFTS, Rec. 4.5 bbls (40.9 API oil)

Murta

DST 1 (1,207.62-1,212.49)

NFTS. Rec. 0.4 bbls oil

Namur

DST 2 (1,234.75-1,239.32)

FTS (20 BOPD, 80 BWPD)

Murta

DST 3 (1,197.25-1,205.18)

NFTS. Rec. 12.8 bbls oil

22

Ulandi-1

23 24

Limestone Creek-9 Murta

Ulandi Ulandi-2

25 26 Source rock samples 28 29

Biala

30 31 32

Biala-7 Jena-11

Jena

DST 3 (1,200.91-1,207.01)

McKinlay

1,237.41

Namur

1,244.45

McKinlay

1,223.32

Jena-12

Murta

1,194.97

Jena-2

Murta

1,200.10

33 Limestone Creek Limestone Creek-9 Murta * Petroleum loss (%) = Original oil (%) - Residual oil (%); Q = flow rate

Wildcat Exploration (Producing Namur; Suspended Murta)

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

9

Selected analytical data

Depth (m) / DST

Residual oil samples (core plugs)

Oil Appraisal/Production well (Murta)

1,241.30

1603

1604

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

charges, respectively). However, SFTE yield permitting, several other fractions from most plugs were also analysed (a total of 54 residual oils, corresponding to the fractions highlighted in Table 2) to better constrain their filling histories. This minimised the risk of assuming an arbitrary cut-off line between ‘‘free’’ and ‘‘adsorbed’’ oils, thus ensuring adequate monitoring of the entire palaeo-charge spectrum. It was impractical (and considered unnecessary) to analyse all 152 of the SFTE fractions recovered.

4. Results and discussion 4.1. General remarks The SFTE yields for the 12 core plugs (3 Murta, 3 McKinlay, and 6 Namur) are summarised in Table 2 which also shows the bulk compositions (aliphatics: aromatics: NSOs) of the SFTE fractions as determined by Iatroscan (most SFTE fractions) or MPLC (DST oils and some SFTE fractions). Methylphenanthrene distributions obtained by GC-MS are discussed on a fieldby-field basis. The core samples analysed are all of high quality in terms of their ‘‘original’’ oil saturations (52–77%), with only one Namur Sandstone sample (#18, Limestone Creek-9) having a lower value of 33% (Table 1). Such high saturations are consistent with their location within live oil columns. England et al. (1987) suggested that a minimum saturation of 50% was necessary for oil to move/migrate within the interconnected pore network. Comparing these saturations with the corresponding residual oil saturations of 9–54%, it can be concluded that petroleum losses (mainly light hydrocarbons, including methane: England et al., 1987) during migration and/or production were relatively small (9–36%: Table 1). More importantly, oil saturation increases upward in all five fields, both within the same rock unit (e.g. Namur Sandstone in Nungeroo-1) and across the boundary between the Namur and McKinlay reservoirs, consistent with both units being hydraulically connected and forming a single oil compartment. On the other hand, the trend is reversed towards the overlying Murta Formation, most likely because this unit hosts a separate oil pool. The non-hydrocarbon contents of the DST oil samples from Biala, Jena, Limestone Creek, and Ulandi Fields are in the range 12–28% (Table 2). A higher value of 46% in the Nungeroo (Murta/Namur) oil may reflect water washing and/or biodegradation. Amongst the DST oils, those of the Murta (±Cadna-owie) Formation are slightly more polar. This could be related to their contact with, and leaching of, local disseminated organic matter. The initial petroleum fractions recovered from the Namur, McKinlay and Murta sam-

ples (mainly those extracted with DCM, i.e. ‘‘free oils’’) are rich in hydrocarbons (mostly aliphatics with lesser aromatics). Polars (resins + asphaltenes) increase from 5% in free oil fractions, through 12% and up to 99.98% in adsorbed oil fractions (Table 2). The high hydrocarbon (mainly aliphatic) contents of these charges agree with the conclusions reached by England (1994) that original fingerprints of subsequent oil pulses can be ‘‘inherited’’ or preserved largely unchanged, especially if diffusional and convective mixing was slow. Whether these free oil fractions all belong to a single charge or to multiple charges requires more detailed molecular characterisation of individual oilfields, as discussed below. The DST oils from the same fields show some bulk chemical resemblance (viz. hydrocarbons versus polars, Table 2) to that of the later charges (or free oils). However, the similarities cannot be described as perfect. These DST oils probably represent the compositional average of all charges, but with chemistries biased towards those of the later influxes that have higher contents of aliphatic hydrocarbons than do the initial pulses. Comparison of the MPI-derived maturities of the DST and residual oils with those of local putative source rocks (0.61–0.66% Rc) within the Murta/McKinlay and Namur sequence (Table 3, see following discussion) shows that local (Cretaceous) contributions cannot be ruled out.

4.2. Oil charges: mixing model The extent of hydrocarbon mixing in Cretaceous reservoirs along the Murteree Ridge, as discussed below on a field-by-field basis, is evaluated using the source and maturity cross-plot devised by Michaelsen and McKirdy (1999, 2001, see Fig. 3). The two mixing curves reflect the existence of (at least) two end-member Permian oil types of contrasting maturity: Family 1 and Family 2. Both lack the araucariacean conifer-derived signature (i.e. low 1-MP/9-MP) and are more mature (i.e. high 2-MP/1-MP) than the Eromanga-derived oils which plot near the bottom-right corner of the diagram. Mixing of such oils will lead to intermediate values for the methylphenanthrene ratios along the trends outlined in Fig. 3. Michaelsen and McKirdy (1999, 2001) found that all Eromanga oils from Queensland, and most of those from South Australia, plot along Ômixing curve 1Õ. However, some South Australian crudes, notably those from the southwestern margin of the Cooper Basin (including the Murteree Ridge), fall on Ômixing curve 2Õ (Fig. 3). The Permian (Family 2) component of these oils was inferred to be expelled from a Patchawarra or Toolachee source (Rc = 0.9–1.0%). As such it differs from the Permian (Family 1) oils elsewhere in the basin that are more mature (Rc = 1.0–1.1%) and characterised by unusual

Table 2 SFTE yields and bulk compositions based on Iatroscan and MPLC Sample No.

5

SFTE Plug Weight (gm)

130.8

Absolute conc. (mg)

Cumulative conc. (mg)

1 2 3 4 5 6 7 8 9 10 11 12 1a 2a 3a 4a 5a

318.2 1059.2 513.8 445.9 352.0 269.7 220.5 185.1 526.3 253.6 32.9 8.1 1.1 8.6 2.9 0.8 0.5

318 1377 1891 2337 2689 2959 3179 3364 3891 4144 4177 4185 4186 4195 4198 4199 4199

1 2 3 4 5 1a 2a 3a 4a 5a

1950.5 1183.1 208.7 184.1 25.3 0.9 2.7 3.0 5.1 0.4

1 2 3 4 5 6 1a 2a 3a 4a 5a

172.0 740.7 601.2 211.3 118.4 25.0 2.5 8.4 19.0 2.6 0.8

4199

Totals

7

139.8

9

80.0

10

15.2

15.5 4.6 0.9 0.3 105.1 5.5 1.6

1 2 3 4 5 6 7 8 9 10 1a 2a 3a 4a 5a

324.7 1187.9 1322.2 1083.2 615.3 370.7 204.9 113.7 50.4 23.8 6.4 1.2 0.3 0.4 0.1

12

Totals

153.7

5305

7.58 32.80 45.04 55.66 64.04 70.46 75.71 80.12 92.65 98.69 99.48 99.67 99.70 99.90 99.97 99.99 100.00

88.32 84.72 86.73 86.57 86.97 87.43 90.13 89.28 86.47 84.44 87.62 77.53 81.16 15.62 12.50 0.01 14.59

6.60 9.84 8.81 6.24 6.38 7.72 9.87 6.22 8.78 9.17 7.74 12.36 6.93 3.12 37.50 0.01 0.01

5.08 5.44 4.46 7.19 6.65 4.85 0.00 4.50 4.75 6.39 4.64 10.11 11.91 81.25 50.00 99.98 85.40

54.73 33.20 5.86 5.17 0.71 0.03 0.08 0.08 0.14 0.01

54.73 87.93 93.78 98.95 99.66 99.69 99.76 99.85 99.99 100.00

89.01 87.41 87.43 87.92 87.50 92.75 23.08 28.57 0.01 16.36

7.31 7.99 7.58 7.87 7.76 0.00 23.08 28.57 0.01 0.01

3.68 4.60 4.99 4.22 4.74 7.25 53.85 42.86 99.98 83.63

9.04 38.95 31.61 11.11 6.23 1.31 0.13 0.44 1.00 0.14 0.04

9.04 47.99 79.60 90.71 96.93 98.25 98.38 98.82 99.82 99.96 100.00

85.99 84.65 90.60 83.11 82.82 80.60 67.20 22.03 0.01 18.75 21.25

7.15 9.83 3.44 10.25 10.56 7.89 6.78 5.08 11.34 25.00 2.52

6.86 5.52 5.96 6.64 6.63 11.51 26.02 72.88 88.66 56.25 76.23

11.61 3.45 0.67 0.22 78.73 4.12 1.20

11.61 15.06 15.73 15.96 94.68 98.80 100.00

82.10 67.27 85.53 84.41 81.79 63.16 78.49

7.18 14.55 5.99 4.99 7.86 12.28 4.92

10.72 18.18 8.48 10.60 10.36 24.56 16.59

6.12 22.39 24.92 20.42 11.60 6.99 3.86 2.14 0.95 0.45 0.12 0.02 0.01 0.01 0.002

6.12 28.51 53.43 73.85 85.45 92.44 96.30 98.44 99.39 99.84 99.96 99.98 99.991 99.998 100.00

84.94 82.95 93.33 86.78 83.31 83.96 84.26 87.37 81.57 79.79 52.23 22.22 5.72 3.66 30.47

7.64 10.34 0.49 7.07 8.29 10.02 8.49 6.31 11.30 10.36 12.04 22.22 6.21 8.33 10.42

7.42 6.72 6.18 6.15 8.40 6.01 7.25 6.31 7.13 9.84 35.73 55.56 88.07 88.01 59.11

0.69

1.65

0.41

0.79

1.00

0.58

0.40

1.73

0.38

0.65

0.75

0.36

0.67 0.95

1.70 1.13

0.28 0.67

13952 8463 1493 1317 181 6 19 21 36 3

0.68

1.73

0.39

0.67

0.91

0.37

0.68 0.78

1.53 1.41

0.30 0.47

2150 9259 7515 2641 1480 313 31 105 238 33 10

0.69

1.40

0.43

1.45

0.39

0.61

1.08

0.30

0.71

1.41

0.38

0.71

1.42

0.40

0.63 0.64

0.68 0.79

0.37 0.39

0.68

1.83

0.38

0.66

1.90

0.34

23779 16 20 21 21 126 132 134

134

Totals

7.58 25.22 12.24 10.62 8.38 6.42 5.25 4.41 12.53 6.04 0.78 0.19 0.03 0.20 0.07 0.02 0.01

Methylphenanthrene distributions MPI-derived 1MP/9MP 2MP/1MP Rc (%)

1020 303 59 20 6914 362 105

8773 324.7 1512.6 2834.8 3918.0 4533.3 4904.0 5108.9 5222.6 5273.0 5296.8 5303.2 5304.4 5304.7 5305.1 5305.2

2113 7729 8602 7047 4003 2412 1333 740 328 155 42 8 2 3 1

0.66

1.47

0.36

0.73

1.27

0.37

1605

1 2 3 1a 2a 3a 4a

Percentages (IATROSCAN or MPLC)* Aliphatics Aromatics Polars

25484 172 913 1514 1725 1844 1869 1871 1880 1899 1901 1902

1901

Totals

2433 8098 3928 3409 2691 2062 1686 1415 4024 1939 252 62 8 66 22 6 4

Cumulative conc. (%)

32100 1951 3134 3342 3526 3552 3553 3555 3558 3563 3564

3564

Totals

SFTE Extract Yield Relative Relative conc. (ppm) conc. (%)

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

Fractions

34506

(continued on next page)

Sample No.

13

SFTE Plug Weight (gm)

134.6

Absolute conc. (mg)

Cumulative conc. (mg)

1 2 3 4 5 6 7 8 1a 2a 3a 4a 5a 6a 7a

315 880 452 267 164 97 63 44 30 19 20 15 13 11 27

315 1195 1647 1914 2078 2175 2238 2282 2312 2331 2351 2366 2379 2390 2417

1

547.1 3757.1 1017.1 346.6 170.3 77.7 36.0 19.3 12.9 22.6 12.6 6.7 3.2 2.6 2.3 8.4 2.0

2417

Totals

16

144.6

2 3 4 5 6 7 8 1a 2a 3a 4a 5a 6a 7a 8a 9a

18

132.5

1 2 3 1a 2a 3a

62.5 30.5 2.8 0.1 0.4 0.7

1 2 3 4 5 6 7 8 1a 2a 3a 4a 5a

422.2 821.5 783.1 701.8 445.2 266.6 145.1 74.4 4.6 7.3 3.4 0.7 0.2

19

Totals

154.9

3676

3784 25983 7034 2397 1178 537 249 133 89 156 87 46 22 18 16 58 14

13.03 36.41 18.70 11.05 6.79 4.01 2.61 1.82 1.24 0.79 0.83 0.62 0.54 0.46 1.12

Percentages (IATROSCAN or MPLC)* Aliphatics

Aromatics

Polars

13.03 49.44 68.14 79.19 85.97 89.99 92.59 94.41 95.66 96.44 97.27 97.89 98.43 98.88 100.00

88.93 84.00 86.11 87.37 83.83 83.23 88.90 87.08 91.55 82.25 75.56 76.13 76.64 71.97 80.36

5.59 9.36 6.15 6.20 6.98 6.40 5.82 7.11 0.01 10.42 5.47 4.11 4.72 11.67 7.56

5.48 6.64 7.74 6.44 9.19 10.37 5.28 5.81 8.45 7.32 18.96 19.76 18.64 16.36 12.08

Methylphenanthrene distributions MPI-derived 1MP/9MP 2MP/1MP Rc (%) 0.67

1.89

0.37

0.67

1.96

0.34

0.67

1.80

0.36

0.68

1.93

0.31

9.98

9.98

62.16 16.83 5.73 2.82 1.29 0.60 0.32 0.21 0.37 0.21 0.11 0.05 0.04 0.04 0.14 0.03

71.21 88.04 93.77 96.59 97.87 98.47 98.79 99.00 99.37 99.58 99.69 99.75 99.79 99.83 99.97 100.00

87.14 84.91 88.78 85.82 85.13 84.48 84.28 81.37 81.74 53.68 42.22 48.98 44.75 48.88 47.26 62.96 37.38

6.24 8.58 5.74 6.49 6.46 7.97 8.78 8.33 10.29 8.09 8.89 10.20 6.56 6.78 8.05 9.88 8.83

6.62 6.52 5.48 7.69 8.41 7.54 6.94 10.29 7.97 38.24 48.89 40.82 48.69 44.35 44.69 27.16 53.78

0.67

1.80

0.37

0.64

1.41

0.37

0.63

0.87

0.36

0.65 0.67 0.67

0.94 1.51 1.04

0.37 0.36 0.35

0.66

1.27

0.38

64.43 31.44 2.89 0.10 0.41 0.72

64.43 95.88 98.76 98.87 99.28 100.00

86.74 82.53 84.17 81.83 12.50 11.21

4.31 5.95 6.38 4.25 12.50 9.63

8.95 11.52 9.46 13.92 75.00 79.16

0.63

0.72

0.38

0.60

1.49

0.19

11.48 22.35 21.30 19.09 12.11 7.25 3.95 2.02 0.13 0.20 0.09 0.02 0.01

11.48 33.83 55.13 74.23 86.34 93.59 97.54 99.56 99.68 99.88 99.98 99.99 100.00

85.13 83.33 86.88 83.80 85.26 90.80 88.71 85.27 60.57 31.25 16.67 0.01 0.01

8.94 10.33 6.65 9.37 9.51 4.05 5.52 9.98 0.01 12.50 33.33 0.01 0.01

5.94 6.33 6.46 6.83 5.22 5.15 5.77 4.75 39.43 56.25 50.00 100.00 100.00

0.71

1.65

0.41

0.70

1.75

0.38

0.70

1.81

0.37

0.70 0.81

1.49 1.71

0.35 0.46

41802 62.5 93.0 95.8 95.9 96.3 97.0

472 230 21 1 3 5

422.2 1243.7 2026.8 2728.6 3173.8 3440.4 3585.5 3659.9 3664.5 3671.8 3675.2 3675.9 3676.1

2726 5303 5056 4531 2874 1721 937 480 30 47 22 5 1

97

Totals

2340 6538 3358 1984 1218 721 468 327 223 141 149 111 97 82 201

Cumulative conc. (%)

17957 547 4304 5321 5668 5838 5916 5952 5971 5984 6007 6019 6026 6029 6032 6034 6043 6045

6045

Totals

SFTE Extract Yield Relative Relative conc. (%) conc. (ppm)

732

23732

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

Fractions

1606

Table 2 (continued)

Sample No.

20

SFTE Plug Weight (gm)

115.7

Fractions

Absolute conc. (mg)

Cumulative conc. (mg)

1 2 3 4 1a 2a 3a

242.3 131.3 104.5 3.9 0.3 0.8 4.0

242.3 373.6 478.1 482.0 482.3 483.1 487.1

1 2 3 4 5 6 7 8 9 10 1a 2a 3a 4a 5a 6a

466.8 478.3 330.0 203.0 101.1 61.1 38.6 26.4 21.8 21.6 2.7 4.4 6.0 4.9 2.2 5

1 2 3 4 5 6 7 8 9 10 11 12 1a 2a 3a 4a 5a 6a 7a 8a

671.9 309.2 242.1 105.4 81.4 71.1 60.2 50.6 76.2 59.4 47.9 43.6 41.4 54.6 54.5 37.0 29.2 27.1 128.1 37.1

487

Totals

132.3

22

Totals

142.1

2228

Percentages (IATROSCAN or MPLC)* Aliphatics Aromatics Polars

49.74 26.96 21.45 0.80 0.06 0.16 0.82

49.74 76.70 98.15 98.95 99.01 99.18 100.00

78.49 82.26 81.29 65.00 80.83 30.00 15.96

6.43 9.06 6.29 17.50 7.29 30.00 5.79

15.08 8.68 12.42 17.50 11.87 40.00 78.25

26.31 26.96 18.60 11.44 5.70 3.44 2.18 1.49 1.23 1.22 0.15 0.25 0.34 0.28 0.12 0.28

26.31 53.28 71.88 83.32 89.02 92.47 94.64 96.13 97.36 98.58 98.73 98.98 99.32 99.59 99.72 100.00

79.39 83.79 82.81 80.71 81.24 83.17 80.18 83.33 79.00 78.24 76.72 28.57 8.89 25.00 6.86 7.63

12.25 8.98 9.87 10.86 8.29 8.11 10.95 10.32 10.88 10.88 9.05 9.52 0.01 25.00 0.01 0.01

8.35 7.22 7.33 8.43 10.47 8.73 8.88 6.35 10.11 10.88 14.23 61.90 91.11 50.00 93.14 92.37

30.16 13.88 10.87 4.73 3.65 3.19 2.70 2.27 3.42 2.67 2.15 1.96 1.86 2.45 2.45 1.66 1.31 1.22 5.75 1.67

30.16 44.04 54.90 59.63 63.29 66.48 69.18 71.45 74.87 77.54 79.69 81.64 83.50 85.95 88.40 90.06 91.37 92.59 98.33 100.00

84.91 83.41 84.56 64.65 77.25 82.63 86.59 83.19 83.41 85.79 86.30 83.14 84.79 78.95 80.61 80.95 80.22 85.20 70.80 81.36

8.70 9.42 8.99 27.10 13.53 10.17 7.20 9.19 10.60 8.00 8.52 10.73 8.62 10.18 8.30 7.81 10.07 6.25 13.64 9.47

6.38 7.17 6.45 8.24 9.22 7.20 6.21 7.62 5.99 6.21 5.18 6.13 6.59 10.88 11.08 11.24 9.70 8.55 15.56 9.17

Methylphenanthrene distributions MPI-derived 1MP/9MP 2MP/1MP Rc (%) 0.70

1.72

0.37

0.73

1.63

0.39

0.73

1.26

0.37

0.68

1.75

0.36

0.68

1.60

0.40

0.65

0.99

0.41

0.87

0.98

0.53

0.64

1.20

0.27

0.68

1.04

0.49

0.69

1.26

0.47

0.67

1.39

0.45

0.67

0.98

0.47

0.69

0.91

0.52

0.72

1.22

0.48

0.74

1.31

0.45

4211 466.8 945.1 1275.1 1478.1 1579.2 1640.3 1678.9 1705.3 1727.1 1748.7 1751.4 1755.8 1761.8 1766.7 1768.9 1773.9

1774

Totals

2094 1135 903 34 3 7 35

Cumulative conc. (%)

3528 3615 2494 1534 764 462 292 200 165 163 20 33 45 37 17 38

13409 671.9 981.1 1223.2 1328.6 1410.0 1481.1 1541.3 1591.9 1668.1 1727.5 1775.4 1819.0 1860.4 1915.0 1969.5 2006.5 2035.7 2062.8 2190.9 2228.0

4728 2176 1704 742 573 500 424 356 536 418 337 307 291 384 384 260 205 191 901 261

15677

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

21

SFTE Extract Yield Relative Relative conc. (ppm) conc. (%)

(continued on next page)

1607

1608

Table 2 (continued)

DST oils

Field

1 3

Alwyn-3 Alwyn Alwyn-5

4 5

Biala-1

6 7 8

Biala

Biala-6

9 10

Biala-7

11

Jena-11

12 13 14

Biala-3

Jena

15

Jena-12

Jena-2

16

DST (&Depth, m)

Aliphatics (%)

Aromatics (%)

Polars (%)

Methylphenanthrene distributions MPI-derived Rc (%)

1MP/9MP

2MP/1MP

McKinlay

DST 1 (1,230.17-1,236.27)

67.7

5.6

26.7

0.61

1.70

0.37

Murta

DST 2 (1,191.77-1,201.52)

36.7

8.7

54.6

0.64

0.96

0.59

McKinlay

DST 1

68.7

9.5

21.8

0.63

1.65

0.40

Namur

DST 4

75.7

7.6

16.7

0.60

1.29

0.37

Cadna-owie/Murta

DST 1 (1,189.94-1,216.15)

69.8

9.3

20.9

0.67

1.48

0.42

Murta/McKinlay

DST 2 (1,227.13-1,242.37)

71.9

10.2

18.0

0.65

1.63

0.40

Murta/McKinlay

DST 1 (1,232.31-1,236.27)

78.9

9.4

11.7

0.67

1.57

0.40

Murta/McKinlay

DST 1 (1,234.75-1,239.93)

72.1

10.6

17.4

0.59

0.97

0.35

Murta

DST 3 (1,187.50-1,206.40)

71.3

9.4

19.3

0.61

1.04

0.46

Murta/McKinlay/Namur

DST 1 (1,233.22-1,242.97)

75.9

9.7

14.4

0.61

1.25

0.36

McKinlay

DST 1 (1,217.98-1,230.78)

71.5

9.0

19.5

0.63

1.67

0.39

Cadna-owie/Murta

DST 3 (1,173.48-1,193.60)

65.8

9.0

25.2

0.64

1.18

0.46

Cadna-owie/Murta

DST 2 (1,181.41-1,221.03)

69.4

9.3

21.3

0.64

1.32

0.45

Cadna-owie/Murta

DST 3 (1,196.04-1,205.79)

67.1

9.3

23.6

0.61

1.09

0.43

Murta/McKinlay

DST 1 (1,225.30-1,229.56)

67.6

9.2

23.2

0.65

1.61

0.40

Murta

DST 2 (1,184.45-1,211.58)

62.2

9.9

27.8

0.64

1.35

0.44

17

Kerinna

Kerinna-1

Hutton

DST 3

73.1

10.1

16.7

0.74

1.27

0.63

18

Kobari

Kobari-1

Murta

DST 1

63.9

7.1

28.9

0.58

0.56

0.63

19

LimestoneCreek

LCk-9

Murta

DST 3 (1,200.91-1,207.01)

69.6

9.9

20.5

0.64

1.27

0.49

20

Mudlalee

Mudlalee-3

Hutton

DST 1

81.4

8.2

10.4

0.46

0.93

0.55

21

Nungeroo

Nungeroo-1 Murta/Namur

DST 2 (1,260.96-1,278.33)

45.6

8.4

46.1

0.60

0.91

0.36

Cadna-owie/Murta

DST 1 (1,191.16-1,212.49)

71.5

8.8

19.7

0.60

0.95

0.39

Namur

DST 2 (1,236.88-1,241.45)

71.3

9.6

19.0

0.63

1.34

0.40

Murta

DST 1 (1,207.62-1,212.49)

67.5

6.4

26.1

0.64

1.26

0.45

Namur

DST 2 (1,234.75-1,239.32)

70.0

10.0

20.0

0.68

1.44

0.44

Murta

DST 3 (1,197.25-1,205.18)

68.0

9.8

22.1

0.61

0.92

0.46

22

Ulandi-1

23 24 25 26

Ulandi Ulandi-2

* Residual oil fractions highlighted (in boxes) and DST oils were analysed by MPLC; and GC-MS other residual oils analysed by Iatroscan

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

2

Reservoir

Well

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

1609

Table 3 Comparison of MPI-derived maturity data (% Rc) for residual and DST oils and source rocks in the Murteree Ridge area Field

Palaeo-charges

Current oil (DST)

Local source rocks

Biala Jena Limestone Creek Nungeroo Ulandi Alwyn

0.40–0.95 (McK–N) 0.63–0.73 (M–McK–N) 0.60–0.67 (McK–N) 0.70–0.81 (N) 0.64–0.87 (M–N) no SFTE performed

0.59–0.67 (C–M–McK–N) 0.61–0.65 (M–McK) 0.64 (M) 0.60 (M–N) 0.60–0.68 (M–N) 0.60–0.64 (M–McK–N)

0.62–0.66 (McK–N) 0.62–0.64 (M–McK) 0.61 (M)

C = Cadna-owie Formation; M = Murta Formation; McK = McKinlay Member; N = Namur Sandstone.

biomarker signatures (viz. rearranged hopanes  17ahopanes; steranes  hopanes). Michaelsen (2002) examined DST oils from five fields along the Murteree Ridge. Based on detailed analysis of their positions on the methylphenanthrene cross-plot, he found some of them to comprise local Jurassic/Cretaceous crude mixed with a high proportion (ca. 60– 70%) of low-maturity Permian oil. The latter was inferred to be a combination of Family 2 oil and a hypothetical early mature (0.55–0.65% Rc) ‘‘Family 3’’ oil. This hypothesis implies that the Cretaceous reservoirs in question received three discrete oil charges. On the other hand, the Murta oil pools at Biala and Dullingari appear to be almost entirely sourced from within the same formation (see also Michaelsen and McKirdy, 1999; Powell et al., 1989). Our study of both residual (SFTE) and DST oils from the same area confirms that they typically plot on or below Ômixing curve 2Õ (i.e. they have low 2-MP/ 1-MP ratios: Fig. 3) signalling the low maturity of their respective Permian and Jurassic/Cretaceous charges. On the other hand, larger variations along the source (1-MP/9-MP) axis are a reflection of the different contributions of Cooper versus Eromanga hydrocarbons to each charge episode. Reservoir studies elsewhere (e.g. in North Sea, Brazil: Leythaeuser et al., 2000; Schwark and Trindade, 2003) likewise reveal systematic molecular differences between residual oils. These differences occur in their saturated and aromatic hydrocarbon fractions, and hence are difficult to explain by degassing or asphaltene precipitation as the core fluids equilibrate to surface temperature and pressure conditions. The clear implication is that the differences are due to the contrasting source and/or maturity of the initial and final oil charges, rather than being artifacts of the sampling or extraction procedure. 4.3. Biala Field In the Biala Field, oil occurs mainly in the Murta/ McKinlay reservoir complex, with one accumulation extending down to the Namur Sandstone at Biala-7. Six DST oils (samples 5–10, Table 1) with fairly uniform

densities (40–42° API) were analysed from these zones at four well locations (Biala-1, 3, 6 and 7). A plug was cut from each of the McKinlay and Namur reservoir cores and their residual oils recovered using the SFTE cell. The intervals from which the McKinlay Member (sample 5; 1237.31 m) and Namur Sandstone (sample 7; 1242.49 m) plugs were cut have high residual oil saturations (So = 44–48%), exhibit moderately bright yellow-green fluorescence and have high permeabilities (50–289 mD). Residual oil fractions were successively retrieved from the McKinlay Member (n = 17) and Namur Sandstone plugs (n = 10) in relatively high cumulative yields (32,100 and 25,484 ppm, respectively). Extract yield generally decreases as the extraction proceeds (Fig. 2(a)). For the McKinlay sample it ranges from 10,531 ppm in the first two fractions to only 10 ppm in the last two fractions; and from 22,415 to 39 ppm for the Namur sample (Table 2). The highest relative yield (25%) from the McKinlay sample was obtained in fraction 2, whereas that from the Namur plug (55%) was retrieved in fraction 1 (Fig. 2(a)). Faster liberation of oil from the latter plug was demonstrated for the entire extraction process, with 99% of the total residual oil recovered in the first four steps (2 h) compared to only half the amount extracted from the McKinlay sample over the same period of time (Fig. 2(a)). Longer extraction was needed for the McKinlay plug, not just because of its higher oil content but probably also due to its lower permeability and the greater tortuosity of its pore network. This, and the time needed to fully saturate the connected pore spaces in the plug, is probably the reason for the extraction behaviour wherein maximum yield was achieved in fraction 2 or 3 rather than in the first fraction. Molecular differences between sequentially recovered residual oil fractions indicate that these reservoirs received multiple hydrocarbon charges of alternating (Cooper versus Eromanga) source affinity (Figs. 3(a) and 4(a)). The McKinlay reservoir was initially filled with highly mature (0.95% Rc) oil of mixed origin (fraction 3a: 40% Cooper, 60% Eromanga), followed by three Eromanga pulses (fractions 2a, 9 and 2) that

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K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

Fig. 2. SFTE residual oil yields from 12 sandstone core plugs of the Cretaceous Murta, McKinlay and Namur reservoir units in five fields (a–d) along the Murteree Ridge. Refer to Tables 1 and 2 for further sample details.

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

1611 Ulandi

Biala-7 1.2 2MP/1MP

100%

Permian end-member oil (Tirrawarra Sst, Merrimelia Field)

1.0 0.8

90%

67%

7

5

50% 3a 5% 2 2 5 7 9 6 2a 2a

9 10

8

McKinlay (sample 5)

0.2

Namur (sample 7)

0.0

0.5

1.0

(a)

1.5

0.8 0.6 0.4

DST oil

0.2

Murta (sample 22) Namur (sample 21)

100%

0.0

7 24

10

23

22

50%

5a 6 8a 9 5%

2

4

25

4a

0.4

60% 33%

16

3a

2a

Murta (sample 10)

14 12 2a

McKinlay (sample 12)

0.2

13

5%

2 15

11

10

9

50%

2a

2 2 8

2MP/1MP

70% 67%

DST oil Murta (sample 9)

100%

2.0

90%

1.2

80%

95%

0.8

1.5

Alwyn, Kerinna, Kobari, and Mudlalee

95%

0.6

1.0 1MP/9MP

1.4 80%

1.0

0.5

(e)

90%

1.2 2MP/1MP

2a 26 12

60%

33%

2a

Jena

1.0

70%

67%

0.8

60%

33%

17

0.6

18

0.4

6 6a

20

50%

5%

3

2

1

4

0.2

Namur (sample 13)

0.0

DST oil

0.0 0.0

0.5

1.0

(b)

1.5

2.0

80% 95%

70%

0.8

67%

60% 33%

0.6 McKinlay (sample 16)

0.2

8

50%

19 5%

2a

2

DST oil

0.4

2 8a

4a

3a

6

Namur (sample 18)

2a

0.0 0.0

0.5

1.0

(c)

1.5

2.0

1MP/9MP

Nungeroo 100%

1.4

90%

1.2

80% 95%

1.0

70% 67%

0.8

60%

33%

0.6

50% 5%

0.4

DST oil

0.2

Namur top (sample 19) Namur bottom (sample 20)

21 2a

2a

2 3a 5 4

8 2

0.0 0.0

0.5

1.0

1.5

2.0

1MP/9MP

90%

1.2 1.0

0.5

Fig. 3 (continued)

Limestone Creek 100%

0.0

(f)

1MP/9MP

1.4

2MP/1MP

70%

67%

2.0

1MP/9MP

1.4

2MP/1MP

80%

1.0

0.0

0.0

(d)

90% 95%

60%

33%

3a

12

DST oil

0.4

70%

100%

1.2

portion of the 'manual mixing' curve

80%

95%

mixing curve 2

0.6

1.4

mixing curve 1

2MP/1MP

1.4

1.0

1.5

2.0

1MP/9MP

Fig. 3. Estimates of the degree of mixing of Cooper- and Eromanga-derived hydrocarbons in fields along and adjacent to the Murteree Ridge, based on the model of Michaelsen and McKirdy (1999, 2001) and manual blending of end-member oils (dashed curve: Arouri and McKirdy, 2004). Sample numbers refer to the SFTE fractions identified in Table 2.

were separated in time by two Cooper charges. These are represented by fraction 12 (70% Permian, 0.65% Rc) and fraction 7 (50% Permian, 0.79% Rc). An almost identical charging pattern was observed for the Namur Sandstone except that the initial Permian input is less evident here (10%, fraction 3a).

The Murta/McKinlay/Namur DST oil from Biala-7 (sample 10), recovered from a comparable depth (1233.22–1242.97 m) in the same interval and borehole where residual oil samples 5 and 7 were taken, is largely (75%) Eromanga-sourced (Figs. 3(a) and 4(a)). This oil seems to represent the compositional average of other DST oils from the Cadna-owie, Murta and McKinlay reservoirs in other Biala wells. These oils vary from being almost entirely Eromanga-sourced (samples 5, 6 and 7 from Biala-1 and 3) to being 50:50 mixtures of Cooper and Eromanga oils (samples 8 and 9 from Biala-6: Figs. 3(a) and 4(a)). It may be significant that DST oils from the latter well show the closest compositional similarity to earlier charges that are predominantly Permian-sourced (sample 7, fraction 5; and sample 5, fraction 12). No flow to surface resulted from either of these drill stem tests and they recovered only small amounts of oil (15 and 0.7 bbls, respectively). This may indicate that the early phase of low-maturity Permian oil has not been followed by any subsequent charges to these traps. The composition of the Namur Sandstone DST oil also mimics the average composition of all the hydrocarbon charges (as exemplified by their residual oils). With one exception (sample 5, fraction 3a), all other residual oil fractions plot along, or close to, ‘‘mixing curve 2’’ of Michaelsen and McKirdy (1999, 2001), confirming the contribution of low-maturity Permian oil to the aforementioned mixed crudes (Fig. 3(a)). It is most significant that the trend of filling is nearly identical for both reservoirs: a minimum of two predominantly Permian pulses alternating with three Eromanga

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K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618 Biala

100 Permian Contribution (%)

Residual oils Fraction 2a

3a

80 A&M model

Fraction 2

7

12

DST oils 8&9 10

5

60

5, 6 & 7 8&9

9 40 20

M&M model

10 5, 6 & 7

0

(a)

Reservoir Filling Sequence

Jena

Permian Contribution (%)

100

Residual oils

A&M

80 model

DST oils

3a

14, 12 13 & 16

10

60

6

40 20

(b)

Fraction 2a

6a

8

14 12

M&M model

Fraction 2

13 & 16 15 & 11

0 Reservoir Filling Sequence

Limestone Creek

100 Permian Contribution (%)

15 & 11

80

Residual oils

A&M model

60

Fraction 2a

4a

DST oil

8

19

8a 40

M&M model

6

3a

Fraction 2

20

19

0

(c)

Permian Contribution (%)

4.4. Jena Field

Reservoir Filling Sequence

Nungeroo

100 80

Residual oils

A&M model

DST oil 21

60 40

Fraction 2a

3a M&M model

8

Fraction 2

5

20 0

(d)

Reservoir Filling Sequence

Ulandi

Permian Contribution (%)

100 80 60 40

8a M&M model

DST oils

Residual oils

A&M model

2a 5a

12

26 22

10

6 9 7

0

(e)

2 24

20

charges can be inferred from both plots (Figs. 3(a) and 4(a)). Interestingly, however, the initial charge (sample 5, fraction 3a) of the McKinlay reservoir still retains its late mature (0.95% Rc) Permian signature (Table 2), whereas that in the underlying Namur Sandstone has co-mingled with more Eromanga oil(s) and hence exhibits a lower maturity (sample 7, fraction 3a, 0.78% Rc). The fact that the earlier Permian contribution is attenuated in the Namur Sandstone (relative to the inter-layered sand/siltstone McKinlay reservoir) is perplexing but may be related to the different grain-size distributions in the two units. The higher permeability of the Namur Sandstone (Table 1) has probably facilitated the removal, by subsequent charge(s), of much of the earlier pulses of hydrocarbons. This explanation is experimentally consistent with the faster experimental recovery of oil by SFTE from the Namur Sandstone sample, as discussed above. On the mixing plot (Fig. 3(a)) there is a subtle separation between the Cadna-owie–Murta–McKinlay DST oils from Biala-6 (samples 8 and 9) and those from Biala-1 and 3 (samples 5, 6, and 7). This same separation is evident in Table 2 that highlights the slightly lower maturities associated with weaker araucariacean conifer-derived molecular signatures (Alexander et al., 1988) in the former crudes, thereby confirming the aforementioned conclusion regarding their mixed origin.

4

23 25

Reservoir Filling Sequence

Fig. 4. Hydrocarbon filling sequence of the Murteree Ridge fields as inferred from the analysis of their residual and DST oils. Estimates of Permian hydrocarbon contributions derived from the manual mixing curve (Arouri and McKirdy, 2004) are compared to those made based on Michaelsen and McKirdyÕs (1999, 2001) model. See Fig. 3 for key to symbols, and Tables 1 and 2 for sample details.

Oil pools have been discovered in the Cadna-owie/ Murta and/or McKinlay reservoirs at Jena. The DST oils (41–43° API) analysed from these zones in Jena-2, 11 and 12 are listed in Table 1 (samples 11–16). Four core plugs (samples 9, 10, 12, 13: Table 1) from successive reservoir (or carrier bed) horizons (2 Murta Formation, 1 McKinlay Member and 1 Namur Sandstone) in Jena-6 and 11 were extracted by the SFTE cell to recover their residual oils. The Murta reservoir has the lowest permeability (7–63 mD) and residual oil saturation (45–47% So), while the Namur Sandstone has the highest (1938 mD, 54% So). The progress of each Jena SFTE experiment is illustrated in Fig. 2(b) which shows yields ranging from 8773 ppm for the Murta core plug (sample 10, distributed over 7 fractions) to 17,957 and 34,506 ppm for the Namur sample 13 and McKinlay sample 12 plugs, respectively (both in 17 steps). The highest recovery from the McKinlay plug is consistent with this reservoir unit being the only producer in this field. Residual oils in the other two units could therefore represent relics of migrating oils or phases of palaeo-oil charges. Extracts recorded the highest yields in either fraction 2 or 3, except for the Murta sample 10 where the maximum recovery (79%) was obtained in fraction 2a. This oil may represent an initial phase trapped within blocked pore

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

spaces that were made accessible only after the removal of later ‘‘over-coatings’’ and its abrupt release by the more polar solvent. The Jena Field is one in which the differing source affinities of its palaeo-oil charges are nicely ÔpreservedÕ. The residual oils from the Murta, McKinlay and Namur reservoir units at Jena-11 selected for GC-MS analysis (samples 10, 12 and 13, respectively) reveal three distinct but complementary charging scenarios (Figs. 3(b) and 4(b)). In the Murta Formation the initial charges (fractions 2a and 3a) have a greater Permian input (70– 80%) than do those in the McKinlay Member (35%), which are nevertheless higher than those entering the Namur Sandstone (ca. 0%). Later charges contained a stronger Eromanga signal (Fig. 4(b)), seemingly as more and more of the Jurassic/Cretaceous source rock intervals entered the oil generation window, before a slight reversal occurred in the lower two reservoir units towards the final charge and the currently producible or DST oils. Nevertheless, a stronger Permian signature is still evident in the DST oils (samples 12, 13, 14, 16) from stratigraphically younger units (Cadna-owie and Murta Formations) than in the DST oils (samples 11 and 15) from the McKinlay reservoir (Fig. 4(b)). Interestingly, the trend towards a higher Permian input in stratigraphically younger reservoirs is evident not only in the early charges but also in the later charging episodes, including the currently producible oil. Maturity variations between different residual (as well as DST) oils are minimal (Table 2). Nevertheless, it is evident, most obviously for the Murta Formation sample 10 from Jena-11, that earlier charges (of greater Permian source affinity) are slightly less mature (0.63% Rc) than the later charge (0.71% Rc). DST oils from the Cadna-owie–Murta–McKinlay reservoirs similarly have uniform maturities (0.61–0.65% Rc), although of these it is a Murta crude (sample 14) that is the least mature.

1613

The residual oil in the Namur Sandstone (sample 18) seems to represent a palaeo-oil column. This would account for the uniformly low yields of all six fractions retrieved on SFTE (Fig. 2(c)). The two residual oil fractions subsequently analysed for their methylphenanthrenes reveal variable proportions of Permian oil, ranging from only traces (i.e. totally Eromanga) in the initial phase (fraction 2a) to ca. 80% in the final stage of the extraction (fraction 2: Fig. 3(c)). More residual oil fractions were retrieved from the McKinlay Member sample (Fig. 2(c)), enabling better elucidation of its charge history (Figs. 3(c) and 4(c)). At least two separate, mainly Permian, pulses (peaking at 45% and 60%) alternated with charges of Jurassic and/or Cretaceous hydrocarbons. The final charges (fraction 2) of the McKinlay and Namur sands display the widest variance in source affinity, with the final oil charge to enter the Namur reservoir being overwhelmingly (80%) Permian in origin (Fig. 3(c)). Note that in this instance there was presumably no subsequent contribution from an intra-Eromanga source rock. It is therefore possible that the Eromanga-derived portion of the Murta/McKinlay oil pool was generated from local Murta source beds (rather than being of Jurassic origin and hence imposing its characteristic araucariacean imprint on the Namur oil). Although DST 3 recovered only trace amounts of oil from the Murta Formation, this is shown to be of mixed Permian/Cretaceous origin (25:75, Fig. 4(c)). As in the residual oils, the Permian component of the DST oil is of low maturity, which is reflected in its proximity to the Ômixing curve 2Õ of Michaelsen and McKirdy (1999, 2001). Maturity variations among different residual oil fractions in both the McKinlay and Namur sands are insignificant (0.60– 0.67% Rc: Table 2), with the DST oil (0.64% Rc) falling within this range.

4.6. Nungeroo Field 4.5. Limestone Creek Field Two core plugs from the McKinlay Member and Namur Sandstone in Limestone Creek-9 (samples 16 and 18: Table 1) were extracted for comparison of their residual oils with petroleum recovered during DST 3 of the overlying Murta reservoir in the same well. The McKinlay core sample has excellent porosity (22.3%) but low permeability (11 mD). Its high oil saturation (31.8%) is in contrast to that of the underlying Namur Sandstone sample (So = 9.2%) which exhibited only very dull yellow fluorescence despite being more porous (Ø = 29.1%) and highly permeable (Ka = 1718 mD). The stark contrast in oil saturation between these two reservoir sands is also reflected in their respective SFTE yields (Namur, 732 ppm; McKinlay, 41,802 ppm: Fig. 2(c)).

The Nungeroo oil discovery in the Namur Sandstone is located on the crest of a NE-SW trending elongate anticlinal dome, about 5 km SSW of Limestone Creek Field (Fig. 1). The drill stem tests conducted in the Nungeroo-1 well aimed at further evaluating the unusual fluorescence associated with comparable oil pay at Limestone Creek. On the mixing plot, the DST 2 oil (Murta–Namur reservoir, sample 21) seems to be of mixed origin (Fig. 3(d)). Its slightly greater Permian affinity (80%) is somewhat at odds with its lower maturity (0.60% Rc) and gravity (41.3° API) when compared to data on the nearby oil pool in the Murta Formation at Limestone Creek-9 discussed above (70% Permian; 0.64% Rc; 42.5° API). Residual oil was retrieved from two Namur Sandstone core plugs (samples 19 and 20, Table 2). Although

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K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

both are highly permeable (Ka = 227–334 mD) and have excellent porosity (Ø = 20.7 23.7%) and oil-saturation (So = 28.1–42.9%), only the upper sample gave a high extract yield (23,733 ppm, cf. 4211 ppm for the lower plug: Table 2). The higher residual oil content and a seemingly more heterogeneous pore/grain size distribution of the upper interval necessitated a longer extraction (13 SFTE steps, cf. only 7 for the lower one: Fig. 2(d)). This probably explains why half of the total residual oil from the lower part of the reservoir was extracted in the first step, while it took three steps to extract a similar percentage of oil from the uppermost Namur Sandstone (Table 2; Fig. 2(d)). The early contribution of Permian oil to the Namur reservoir at Nungeroo-1, as revealed by many of its residual oil fractions (Figs. 3(d) and 4(d)), was slightly less pronounced (<20%) than that recorded in the DST oil (55%). The Permian influence reached only the bottom Namur Sandstone (sample 20, fraction 2a), while the uppermost part of the reservoir (sample 19) was totally filled with Eromanga oil. The maturity of the DST oil recovered from the Murta–Namur interval (0.60% Rc) is appreciably lower than those of the residual oils (0.70–0.81% Rc). This is probably a reflection of the larger proportion of low-maturity Permian oil that was displaced upwards by subsequent charges. It could also be an overprint from low-maturity intra-Murta source beds in the interval where the DST was conducted. 4.7. Ulandi Field Oil in the Ulandi Field is produced from the Murta/ Namur silt-sand transition (Table 1). Cores cut from this interval in several wells had oil oozing from their surfaces. Plugs from two of these cores (Namur Sandstone in Ulandi-1, and Murta Formation in Ulandi-2) were extracted to recover their residual oil contents (samples 21 and 22, respectively; Table 1). The Namur sample is characterised by high permeability (927 mD), excellent porosity (24.3%) and good oil saturation (30.9%), together with a bright yellowish green, patchy fluorescence. The last feature extends along the entire 9.14 m length of the Ulandi-1 (Namur) core. The Murta sample is similarly porous (Ø = 26.2%) and rich in residual oil (So = 42.6%) but considerably less permeable (Ka = 28 mD), and therefore required a longer extraction (20 SFTE steps, cf. 16 for the Namur sample: Fig. 2(e)). As expected for such high oil saturations, both the Namur and Murta plugs gave high extraction yields (13,409 and 15,677 ppm, respectively). DST oils from the Murta reservoir in both Ulandi-1 and -2 (samples 22 and 26, Table 1) consistently have higher Permian inputs (50–60%) and are subtly less mature than their respective Namur DST oils (samples 23 and 25, Table 1: <20% Permian) (Figs. 3(e) and 4(e); Table 2). This maturity stratification is best shown at

Ulandi-2 where Rc increases from 0.61% in the top Murta oil (sample 26, 1197.25–1205.18 m), through 0.64% in the lower Murta oil (sample 24, 1207.62–1212.49 m), to 0.68% in the Namur oil (sample 25, 1234.75–1239.32 m). The downward increase in maturity is paralleled by an increase in the Permian contribution to the reservoir (Figs. 3(e) and 4(e)). The hydrocarbon charges to both reservoir units alternated from being predominantly Permian (ca. 60%) to being almost totally Eromanga-derived. A slightly higher proportion of Jurassic/Cretaceous oil is evident in the final charges reaching the Namur Sandstone (as evident in SFTE fractions 7 and 4: Figs. 3(e) and 4(e)). The fact that these later hydrocarbon pulses are more pronounced in the upper Namur sands suggests that they are recent and not large enough to reach the overlying Murta reservoir. This may explain why the Namur-hosted DST oils contain a higher proportion of Eromanga-sourced hydrocarbons, more than do those in the overlying Murta Formation, and perhaps also why only small amounts of oil with no flow to surface were recovered on drill stem testing. 4.8. Alwyn Field The Alwyn Field presents a good example of reservoir compartmentalisation on the southern Murteree Horst. DST oils from the contiguous Murta and McKinlay sands in Alwyn-3 (samples 2 and 1, respectively: Table 1) have markedly different 1-MP/9-MP signatures. The shallower reservoir unit registers a 60% Permian contribution, whereas the McKinlay oil is of completely Eromanga (and probably Cretaceous) source affinity (Fig. 3(f)). About 28 bbls of oil were recovered from the McKinlay reservoir during drill stem testing, and only 12 bbls from the Murta Formation with no flow to surface (Table 1). From the distribution of these small accumulations, it is conceivable that the initial Permian charge migrating through (and probably residing in) the McKinlay sands was subsequently displaced upwards into the overlying Murta Formation. No cores from this field were available for SFTE and residual oil analysis to confirm this speculation regarding previous charges. However, the observed oil ‘‘stratification’’ clearly suggests that an effective seal was probably formed after the migration of the Permian oil into the Murta Formation, but seemingly before locally sourced Cretaceous oil started accumulating in the McKinlay Member, thereby creating two separate compartments or oil plays. Although the McKinlay oil in the nearby Alwyn-5 well is similarly of local origin (oil sample 3: Fig. 3(f)), the situation is somewhat different here because the deeper reservoir unit (Namur Sandstone, oil sample 4: Fig. 3(f)) has acquired 20% of its charge from a Permian source. A plausible scenario for oil filling here is that the same Permian pulse charged the three reservoir units

K.R. Arouri et al. / Organic Geochemistry 35 (2004) 1597–1618

and subsequently resulted in ‘‘stratification’’ between the Namur Sandstone (20% Permian) and Murta Formation (60% Permian) oils. An enclosed McKinlay petroleum system that hinders the infiltration of Permian oil can explain its indigenous (intra-Eromanga) hydrocarbon composition. The observed oil stratification may alternatively be a result of two separate Permian pulses, with the latter only reaching the Namur Sandstone.

4.9. Fields in the immediate vicinity of the Murteree Ridge These include the Kerinna and Mudlalee Fields in which the Hutton Sandstone is the principal reservoir, and the Kobari Field located further south in the Tenappera Trough where oil resides in the Murta Formation (Fig. 1(a); Table 1). In these fields, the Permian component of the pooled oil increases, while its maturity decreases, with increasing distance from the Murteree

1615

Ridge [Kerinna (sample 17): 25% Permian, 0.74% Rc; Mudlalee (sample 20): 60% Permian, 0.65% Rc; and Kobari (sample 18): 90% Permian, 0.58% Rc: Fig. 3(f)]. Aspects of the biomarker distributions of the oils pooled in the Hutton Sandstone at Kerinna and Mudlalee are best explained if they represent mixtures of Early Permian oil families 1 and 2 (cf. McKirdy et al., 1997; Michaelsen and McKirdy, 2001), variably co-mingled with locally derived Jurassic hydrocarbons. Features of their saturated hydrocarbons include: high C29 sterane abb/aaa and 20S/20R ratios (2.8 and 2.7, respectively), and the highest abundances of neohopanes, diahopanes and diasteranes. These oils also have the lowest C29/C30 hopane and sterane/hopane ratios and tricyclic terpane abundances. Contrasting molecular maturities in the same oil sample are consistent with mixing of more than one charge. No cores were available from these fields to sample for residual oil analysis. Of all the 84 DST oils analysed in a larger study of which this report is part, these

100 DST oils 18

Permian Contribution (%)

80

60

26

10

5 22 7

16 21

12

20 2 17 4

21 14 19 10 25

3 1

15

19 13

40

20 Fraction 2

Fraction 2a 0

Reservoir Filling Sequence

(a)

Permian Contribution (%)

100

80

10

Kobari (M)

Mud (H)

26

60

21 40

5

Alw3 (M)

14

16

10 20

0

22 21 7 19

Ke (H) Alw5

12

19 (N) 25 Alw (McK)

13 Fraction 2a

(b)

DST oils

Key to reservoir units and oil fields : M = Murta Alw = Alwyn McK = McKinlay Mud = Mudlalee N = Namur Ke = Kerinna H = Hutton

Fraction 2

15

Reservoir Filling Sequence

Fig. 5. Composite accumulation history of the Murteree Ridge oil fields as inferred from the hydrocarbon filling sequence of their Cretaceous reservoirs: (a) A & M model, and (b) M & M model. See Fig. 3 for key to numbers and symbols of residual and DST oil samples.

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two Hutton crudes have the highest concentrations of abb-steranes. This suggests that they have migrated the longest distances (Seifert and Moldowan, 1978; Vincent et al., 1985), with their source input likely to include a contribution from Cambrian marine carbonates of the underlying Warburton Basin (Fig. 1(b)), an inference consistent with their very low pristane/phytane ratio (Pr/Ph = 0.23). Oil in the Murta Formation at Kobari in the Tenappera Trough (Fig. 1(a)) seems to have a unique origin different to those pools on, and to the north of, the Murteree Ridge. It is the least mature oil in this area (0.58% Rc; C29 sterane 20S/20R = 0.27; minimal abbsteranes; minimal rearranged hopanes and steranes) and has the highest Pr/Ph ratio of 2.9. Its methylphenanthrene isomer distributions (Figs. 3(f) and 5) suggest a predominantly Permian source affinity. Nevertheless, its methylphenanthrene ratio (MPR = 2-MP/1-MP) is only slightly higher than those of typical Ôwholly EromangaÕ crudes. This may indicate the early expulsion of barely mature Permian oil, now preserved largely as a Ôpalaeo-family 3 oilÕ (cf. Michaelsen, 2002). Oils of the Kobari (Murta Formation) type appear likely to be restricted to the southernmost areas of the Cooper Basin where the oil-prone coals of the Patchawarra Formation are early mature (0.5–0.75% Ro: Michaelsen and McKirdy, 2001). Alternatively, it is possible that the oilÕs apparent low maturity may be an artifact of contamination/leaching during migration through less mature Eromanga strata.

4.10. Revised mixing ratios based on artificial blending of end-member oils The charge histories of the Murteree Ridge fields outlined in the preceding discussion are based on the mixing model proposed by Michaelsen and McKirdy (1999, 2001) and refined by Michaelsen (2002). The mixing curves of this model, although still valid, have recently been re-calibrated using results from the artificial blending of the same two end-member Permian (Family 1) and Jurassic oils (Arouri and McKirdy, 2004). The latter authors showed that the original model over-estimates the Jurassic contribution to the mixed oil. Thus, the proportions of Permian hydrocarbons in the different charges reaching these Cretaceous reservoirs are actually higher, as shown by the curves labelled ÔA & M modelÕ in Fig. 4 and summarised in Fig. 5. At each stage of their charge histories, the three stacked reservoirs of the Jena Field maintained the same relativity of Permian input (Murta Formation > McKinlay Member > Namur Sandstone). Moreover, the same fluctuating filling pattern (55–80% Permian-sourced) in these reservoirs is also evident in the surrounding fields (Biala, Limestone Creek, Nungeroo and Ulandi). Finally, it is noteworthy that the associated DST oils generally have mixing ratios

of Cooper and Eromanga-sourced hydrocarbons that approximate the average of those in the different oil charges which reached their respective reservoirs. 4.11. Geological evidence for multiple charge events Modelling of the burial and thermal histories of the Cooper/Eromanga succession led Deighton and Hill (1998) to propose four discrete hydrocarbon expulsion events. The last three of these events (at 105, 90 and 20–0 Ma: Fig. 1(b)) may well explain the three pulses of Permian oil evident in the summative charge histories of the Cretaceous reservoirs on the Murteree Ridge (Fig. 5). Alternatively, the observed pulses may all be linked to the major Late Cretaceous event. These pulses appear to be superimposed on a background charge of locally derived Jurassic and/or Cretaceous oil. In fact, the apparent cyclicity in the source affinity of the oil entering these reservoirs is exactly what might be expected in a complex basin system characterised by multiple heating events, stacked source-reservoir couplets, and cap rocks of variable lateral extent and sealing efficiency.

5. Summary The petroleum system of the Murteree Ridge area contains hydrocarbons of mixed Cooper (Permian) and Eromanga (Jurassic and/or Cretaceous) origin. The filling histories of its Cretaceous reservoirs are summarised in Fig. 5. Multiple charging episodes involving oils varying in source affinity up to about 80% Permian are clearly evident and appear to have fed the three reservoir units: Murta Formation, McKinlay Member and Namur Sandstone in a complementary manner. Consistently throughout their charging histories, the Murta/ McKinlay reservoirs show evidence of retaining a higher proportion of Permian-sourced hydrocarbons in their mixed oils than do those in the underlying Namur Sandstone. Although most of these charges are of low maturity ( 6 0.73% Rc), a more mature (0.78–0.95% Rc) early charge is evident in the Namur reservoir at Nungeroo, Ulandi, and Biala Fields, as well as in the overlying McKinlay Member at Biala-7. These more mature pulses are not reflected in the DST oils that instead show a limited range of maturity (0.59–0.68% Rc: Table 3), representing the compositional average of all previous charges to their respective reservoirs, as indicated in Fig. 5. This multiple filling scenario is the opposite of that inferred for the Dirkala, Garanjanie, Thurakinna and Wancoocha Fields, located 15–20 km to the west near the edge of the Cooper Basin. Here the maturity of both residual and DST oils increases with reservoir age (Cretaceous, Jurassic and Permian), and both types of oil are more mature than the local putative source rocks (Yu, 2000; McKirdy et al., 2001).

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Acknowledgements This study is part of a larger investigation: ‘‘Conditions and effects of hydrocarbon fluid flow in the subsurface of the Cooper/Eromanga Basin’’, which was financed by ARC SPIRT Grant C39943025. Additional funding was provided by PIRSA and Santos Limited. The authors thank Yassin Hardi, Markus Schmidt, Christian Hallmann, Alexandra Richter and Bianca Stapper (University of Cologne) for their invaluable technical assistance. Reviews of the original manuscript by R. di Primio and C.J. Boreham led to a significantly improved paper and are highly appreciated. Finally, we wish to acknowledge the efforts of David Gravestock (PIRSA), our former co-investigator who died in the early stages of this project. Without his foresight and enthusiastic advocacy, it is doubtful whether the project would have been possible. Guest Associate Editor—Volker Dieckmann

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