petroleum systems in the amadeus basin, central … amadeus petroleum... · petroleum systems in...

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Petroleum systems in the Amadeus Basin: Were they all oil prone? TR Marshall 1 , IA Dyson 2 and Keyu Liu 3 The Amadeus Basin in central Australia is a broad intracratonic feature, covering some 170 000 km 2 (65 500 square miles). It has been the subject of petroleum exploration for almost 50 years, and is productive from Ordovician reservoirs at both the Mereenie (oil/ gas) and Palm Valley (gas) fields. As part of an NTGS project, a number of wells were sampled for analysis by QGF, QGF-E and GOI methods, patented CSIRO Petroleum fluid history analysis techniques that detect oil exclusively. The Neoproterozoic part of the Amadeus Basin succession was targeted by this study to ascertain if oil had been present in any of the wells sampled. Failure analysis indicates most dry wells were drilled off structure; therefore, at those locations, analytical results should reflect a migration pathway. QGF and QGF-E data confirmed that oil had been present in the samples, and subsequent GOI analysis confirmed that it was not captured in accumulations, therefore the analysed zones are interpreted to be migration pathways. This is consistent with the interpretation that, due to lack of information (seismic) available pre-drill, most wells were drilled off structure, which in turn suggests that there may still be untested potential in some of the ‘drilled’ prospects in the Amadeus Basin. The results of analyses from Finke-1 are the most interesting as they strongly suggest that a 50+ m palaeo- oil column is present at the well location. The source of some of the oil is likely to be from the Neoproterozoic portion of the Amadeus Basin succession. This important result builds on source rock studies performed over the last 40 years, and demonstrates that not only was the Neoproterozoic capable of producing oil, in fact, it has. This opens up a rich new vein of exploration possibilities in the Amadeus Basin, and future exploration models should be refined to focus on the Neoproterozoic for oil, as well as gas. Keywords: Northern Territory, Amadeus Basin, Neoproterozoic, Cambrian, Ordovician, fluid history analysis, QGF analysis, QGF-E analysis, GOI analysis, FOI analysis, stratigraphy, Finke-, petroleum exploration, petroleum geology, hydrocarbons, petroleum accumulation, migration, petroleum potential INTROduCTION The Amadeus Basin is an asymmetric, east–west trending, intracratonic depression covering approximately 70 000 km 2 (65 500 square miles) of central Australia (Figure 1). It contains a Neoproterozoic to Late Devonian sedimentary section that reaches a maximum thickness of approximately 7 km (Figure 2). The basin is bounded to the north by the Precambrian Arunta Complex, and to the south by the Musgrave–Mann Complex and the Olia Gneiss. To the west and east, the present basin margins are obscured by a cover of Permian and younger sediments. The distribution of Late Proterozoic sediments was controlled by an east–west trending hinge-line (Angas Lineament, Marshall and Dyson 2007), across the north central part of the basin, from which the thickness of section increases both northward and southward. The Palaeozoic Petroleum systems in the Amadeus Basin, central Australia: Were they all oil prone? 1 Vibrante Solutions, 74 Alice Street, Sefton Park, Adelaide SA 5083. 2 Salt Tectonics Australia Research, PO Box 22, Aldgate SA 554. 3 CSIRO Petroleum, PO Box 30, Bentley WA 602. Alice Springs Yulara 130° 131° 132° 133° 134° -24° -25° 129° A06-137.ai STUART HIGHWAY LASSETER HIGHWAY 0 50 100 km N Mereenie Palm Valley Figure 1. Location map showing the Amadeus Basin in central Australia. Black lines represent axial traces of anticlines defined by outcrop, seismic and airborne magnetic data.

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Page 1: Petroleum systems in the Amadeus Basin, central … Amadeus petroleum... · Petroleum systems in the Amadeus Basin: Were they all oil prone? TR Marshall1, IA Dyson2 and Keyu Liu3

Petroleum systems in the Amadeus Basin: Were they all oil prone?

TR Marshall1, IA Dyson2 and Keyu Liu3

The Amadeus Basin in central Australia is a broad intracratonic feature, covering some 170 000 km2 (65 500 square miles). It has been the subject of petroleum exploration for almost 50 years, and is productive from Ordovician reservoirs at both the Mereenie (oil/gas) and Palm Valley (gas) fields. As part of an NTGS project, a number of wells were sampled for analysis by QGF, QGF-E and GOI methods, patented CSIRO Petroleum fluid history analysis techniques that detect oil exclusively. The Neoproterozoic part of the Amadeus Basin succession was targeted by this study to ascertain if oil had been present in any of the wells sampled. Failure analysis indicates most dry wells were drilled off structure; therefore, at those locations, analytical results should reflect a migration pathway.

QGF and QGF-E data confirmed that oil had been present in the samples, and subsequent GOI analysis confirmed that it was not captured in accumulations, therefore the analysed zones are interpreted to be migration pathways. This is consistent with the interpretation that, due to lack of information (seismic) available pre-drill, most wells were drilled off structure, which in turn suggests that there may still be untested potential in some of the ‘drilled’ prospects in the Amadeus Basin.

The results of analyses from Finke-1 are the most interesting as they strongly suggest that a 50+ m palaeo-oil column is present at the well location. The source of some of the oil is likely to be from the Neoproterozoic

portion of the Amadeus Basin succession. This important result builds on source rock studies performed over the last 40 years, and demonstrates that not only was the Neoproterozoic capable of producing oil, in fact, it has.

This opens up a rich new vein of exploration possibilities in the Amadeus Basin, and future exploration models should be refined to focus on the Neoproterozoic for oil, as well as gas.

Keywords: Northern Territory, Amadeus Basin, Neoproterozoic, Cambrian, Ordovician, fluid history analysis, QGF analysis, QGF-E analysis, GOI analysis, FOI analysis, stratigraphy, Finke-�, petroleum exploration, petroleum geology, hydrocarbons, petroleum accumulation, migration, petroleum potential

INTROduCTION

The Amadeus Basin is an asymmetric, east–west trending, intracratonic depression covering approximately �70 000 km2 (65 500 square miles) of central Australia (Figure 1). It contains a Neoproterozoic to Late Devonian sedimentary section that reaches a maximum thickness of approximately �7 km (Figure 2). The basin is bounded to the north by the Precambrian Arunta Complex, and to the south by the Musgrave–Mann Complex and the Olia Gneiss. To the west and east, the present basin margins are obscured by a cover of Permian and younger sediments.

The distribution of Late Proterozoic sediments was controlled by an east–west trending hinge-line (Angas Lineament, Marshall and Dyson 2007), across the north central part of the basin, from which the thickness of section increases both northward and southward. The Palaeozoic

Petroleum systems in the Amadeus Basin, central Australia: Were they all oil prone?

1 Vibrante Solutions, 74 Alice Street, Sefton Park, Adelaide SA 5083.2 Salt Tectonics Australia Research, PO Box 22�, Aldgate SA 5�54.3 CSIRO Petroleum, PO Box ��30, Bentley WA 6�02.

Alice Springs

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Figure 1. Location map showing the Amadeus Basin in central Australia. Black lines represent axial traces of anticlines defined by outcrop, seismic and airborne magnetic data.

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Marshall et al

section is thickest along the present northern margin of the basin, and thins depositionally to the south.

The Amadeus Basin is a proven petroleum province containing initial recoverable, proved, probable and possible reserves estimated at 37 million barrels of oil and 427 billion cubic feet of gas (Jackson et al �984). Most hydrocarbon occurrences, including the oil and gas reserves at Mereenie and Palm Valley, have been found in Ordovician sandstone. Cambrian reservoirs, particularly in the Arumbera Sandstone (see Figure 2), have been the main exploration objective in the eastern Amadeus Basin. The small Neoproterozoic Dingo gasfield (currently uneconomic) also occurs there.

The Amadeus Basin is a salt-cored fold and thrust belt, with multiple episodes of deformation (both tectonic and halokinetic), spanning some 800 million years. These continuous events have strongly impacted on the distribution and type of source, seals, and reservoirs at both regional and local scales.

The aim of this paper is to briefly review the lithostratigraphic petroleum systems present in the Amadeus Basin and offer insights, using new data, into their hydrocarbon phases. It presents additional new evidence that gas-prone Neoproterozoic sedimentary rocks have also produced oil, but it is beyond the scope of the paper to discuss source rock characteristics in detail. Previous authors (eg Kurylowicz �976, McKirdy �977, Oterdoom �982, Gorter �982, �983, Jackson et al �984, Summons and Powell �99�, Marshall 2004) have presented geochemical studies on the capacity of various parts of the Amadeus Basin succession to produce hydrocarbons (gas and liquids); this paper presents evidence that the Neoproterozoic did generate liquids. The CSIRO techniques discussed in this paper do not measure/detect the presence of gas, and therefore no comments are made on gas generation from the Neoproterozoic of the basin in this paper.

PETROlEum SySTEmS OF ThE AmAdEuS BASIN

This paper follows the petroleum systems framework of Marshall (2003) for the Amadeus Basin (see Figure 2). Given the paucity of data in the basin (35 exploration wells over �70 000 km2 or 65 500 square miles), it is currently very difficult to develop a sequence stratigraphy-style system framework, although it is currently being attempted (Dyson in prep).

Marshall (2003) defined 5 petroleum systems in the Amadeus Basin, numbered � (oldest: Neoproterozoic) to 5 (youngest: Ordovician, see Figure 2). Currently, the only commercially productive petroleum system is number 5 (Marshall 2003). This Ordovician system encompasses the Mereenie, Palm Valley and West Walker hydrocarbon occurrences and is responsible for the accumulations of oil and gas at both the Mereenie and Palm Valley fields. Sub-economic Neoproterozoic discoveries of hydrocarbons (gas) have been made within system 4 (Orange-� and -2, Dingo-� to -5), system 2 (Ooraminna-�) and system � (Magee-�). Despite numerous oil shows, the general view of the exploration community has been that anything older than Ordovician would be a gas-prone target only.

Previous workers (eg Kurylowicz �976, McKirdy �977, Oterdoom �982, Gorter �982, �983, Marty et al  �982,

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Figure 2. Generalised stratigraphic column for the Amadeus Basin (modified after Weste 1990), showing petroleum systems defined by Marshall (2004).

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Petroleum systems in the Amadeus Basin: Were they all oil prone?

Jackson et al �984, Summons and Powell �99�), generally considered the source-rock potential of the Neoproterozoic succession in the Amadeus Basin to be negligible to nil and predominantly gas prone, largely based on limited, and in some cases, poor-quality data. However, Marshall (2003, 2004) demonstrated that there was source potential within this part of the succession, by including more recent data gathered by the Northern Territory Geological Survey (NTGS), and using the same style of analysis (geochemical plots) as used by previous authors. This conclusion was based on newer geochemical results (effectively indicating some source units were ‘type 2’ (oil and gas), not just ‘type 3’ (gas) source rocks), laced with analogies to the productive west Siberian basins. Essentially, the source-rock characteristics that are measured today are only remnants of the original potential of the intervals; they have been severely degraded due to the production and expulsion of hydrocarbons, particularly their total organic carbon values (TOC). In the nearby Officer Basin, immature sediments of the same age (?Neoproterozoic), in the NJD-� drillhole, yielded TOC values in excess of 6% (Hocking 2002). This represents a legitimate Australian analogy for the potential source characteristics of sediments in the Neoproterozoic Amadeus Basin.

FINkE-1: A NEOPROTEROzOIC OIl dISCOVERy IN ThE AmAdEuS BASIN?

The Finke Prospect is located �00 km southwest of Alice Springs (Figure 3). The nearest wells to the prospect are James Range-�A, 7.5 km to the east, Palm Valley-�, 25 km to the northwest and Highway-�, 55 km to the southeast. No seismic data had been acquired over the prospect; the structure was defined purely on outcrop information and photogeological interpretation.

Finke-� was drilled to a total depth of 509.3 m during April and May �983. It was drilled primarily to assess the hydrocarbon potential of the Arumbera Sandstone and test the pre-Arumbera section (Gorter �984), and was sited on the maximum gas seepage anomaly detected by a Vaporsearch gas sniffer survey of the James Ranges, conducted in July �98�. The well tested the validity of the Vaporsearch technique, as well as an independent closure west of the dry James Range-�A well to the east (Gorter �984). No gas seepage anomaly was associated with James Range-�A.

Finke-� penetrated 2�4 m of Cambrian shale and carbonate with minor sandstone, before encountering a very much reduced clastic succession, tentatively assigned to the Arumbera Sandstone (Gorter �984). No hydrocarbons were noted as occurring in this section in the well completion report.

Below the 24 m of ?Arumbera Sandstone, the well penetrated 27�.3 m of Late Neoproterozoic dolostone and shale, and reached its total depth in Bitter Springs Formation dolostone (Loves Creek Member). Minor shows of live oil were found in non-effective vuggy porosity in the upper dolomitic/shale section, but where effective porosity was encountered, it proved to contain slightly brackish water, possibly indicative of flushing (Gorter 1984, Table 1).

The well penetrated two units that contained live oil bleeds within Neoproterozoic sedimentary rocks (Gorter �984). Geochemical aspects of the recovered oils were detailed in Gorter (�984); in brief terms, the analytical work confirms the former presence of two different oil families and/or charges. A full description and discussion of the geochemistry of these oils is in Gorter (�984) and Marshall (in prep). Prior to this study, data (from visual inspection and geochemistry) for Finke-� already suggested the presence of Neoproterozoic oil; however, the new information presented below puts this into a regional oil perspective.

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Figure 3. Location of Finke-�, relative to Alice Springs and surrounding petroleum wells. Axial traces of significant folds in the northeastern Amadeus Basin are also shown.

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FluId hISTORy ANAlySIS: A CSIRO TEChNIQuE

A well failure audit (see Munroe et al 2004) suggests that most wells in the Amadeus Basin were drilled off structure. Historically, wells were preferentially sited on surface-expressed structural highs (anticlines) and were also based on very coarse, poor seismic data (where acquired). These facts pose a fundamental question: if the wells were drilled off structure, potentially missing accumulations, how can one prove that there was oil in the system?

The CSIRO-patented fluid-history analysis methods of QGF (Quantity of Grain Fluorescence), QGF-E (Quantity of Grain Fluorescence and Extract) and GOI (Grains containing Oil Inclusions) are able to ascertain the presence of oil in residual/palaeo-oil zones and were used on sampled intervals of selected Amadeus Basin wells. It should be emphasised that these techniques only detect the presence of oil, they do not reflect the presence of dry gas. Table 2 summarises the main differences between the values produced by QGF, QGF-E and GOI analyses. Note that the CSIRO interpretation is calibrated on the basis of results of the same analyses performed on samples from offshore wells, which is standard procedure.

For a detailed explanation of the techniques and concepts involved, see Burruss et al �98�, Hagemann and Hollerbach �985 Eadington et al �996, �999, 2004, England et al �987, Lisk et al �994, �998, Palmer et al �999, Liu and Eadington 2005 and Liu et al in press. In the context of this paper, a brief extract of the procedures is provided from CSIRO4.

Quantitative Grain Fluorescence is a technique to detect current and palaeo-oil zones by measuring the intensity of fluorescence from hydrocarbons sealed in fluid inclusions and at the surface of siliciclastic grains excited by short-wavelength UV light. The amount of fluorescence is small and detection of the emitted fluorescence requires a sensitive fluorescence spectrophotometer. A fluorescence spectrum is recorded from 300 to 600 nm and the QGF Index is calculated as the average fluorescence emission between 375 nm and 475 nm, normalised to the spectral intensity at 300 nm wavelength.

Present-day oil zones and palaeo-oil zones generally have QGF Index values greater than 4 and QGF Ratios greater than �.5. Across the oil/palaeo-oil–water contact, the QGF Index normally drops sharply to several times lower than that from the oil/palaeo-oil zone and QGF Ratios drop

below 1. Most water-zone samples have a relatively flat fluorescence spectrum at wavelengths from 375 to 475 nm, compared with samples from oil zones and palaeo-oil zones.

The Quantity of Grain Fluorescence and Extract technique differs from QGF simply in that the fluorescence measured is taken from the extract of grain coatings after washing, instead of being performed on the physical grain surfaces.

The Grains containing Oil Inclusions technique is a petrographic method that records the abundance of oil-bearing fluid inclusions in samples of sandstone. The measured parameter is the percentage of quartz and feldspar (framework) grains that contain oil inclusions within a thin section prepared from either core or cuttings material. The framework grains represent proxy sample points for the adjacent pore space, with the fluid inclusion representing a sample of the reservoir fluid. Significantly, samples of oil are trapped and sealed from the pore network as the reservoir fills, thus allowing evidence to be retained that the adjacent pore spaces were once oil bearing, even if the rocks are currently water wet. Oil saturation is simply the measure of how many pores are filled with oil and this allows the GOI count to be used as an indicator of relative oil saturation. In a migration path setting, it is generally accepted that oil saturation is unlikely to exceed 5% and consequently only a small number of grains have the opportunity to trap an oil inclusion. In contrast, the high oil saturation (30–70+%) experienced during oil accumulation exposes a much larger number of grains to oil and consequently, many more grains have the opportunity to trap oil inclusions.

RESulTS

The results of QGF and QGF-E analyses on samples taken from Amadeus Basin wells are summarised in Table 3. For a detailed presentation of results, see Liu and Fenton (2004) and Marshall (in prep).

Based on the results, Liu et al (2004) interpreted the presence of current residual oil and palaeo-oils in wells noted in Table 4.

In some cases, the small amount of sample (less than 0.5 g), caused problems during the analysis. As part of the procedure, samples were normalised to �.2 g (as per Liu and Eadington 2005); in some cases, this ‘magnification’ was quite pronounced. If the accentuated spectra produced was similar in shape to the chemical blank (Dichloromethane or ‘DCM’) used, and/or had a relatively high signal to noise ratio, the results were disregarded.

Some of the sampling intervals were also not optimal, as the age and variable tectonic (thermal) history suggests that periodic charge could have taken place. The relative tectonic

Table 1. Stratigraphic succession penetrated in Finke-�.

Formation Top (mKB)

Thickness (m) Lithology

Quaternary 0 6 scree/outwash upper Giles Creek Dolostone 6 63 siltstone, limestone middle Giles Creek Dolostone 69 120 siltstone, dolostone lower Giles Creek Dolostone 189 25 siltstone ?Arumbera Sandstone 214 24 sandstone, chert Finke beds 238 35 dolostone Johnnys Creek beds 273 126 dolostone, siltstone Bitter Springs Formation 399 190.3 dolostone

Table 2. Principle differences between values produced by QGF, QGF-E and GOI analyses. NA = not applicable.

Oil zone Current residual zone

Palaeo-oil zone

Water zone

GOI high NA high low QGF high NA high low

QGF-E high high–medium low low 4 See also http://www.csiro.au/services/ps1a8.html (QGF and QGF-E Service) and http://www.csiro.au/services/ps1ag.html (GOI Service), accessed April 2007).

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Depth CSIRO no Well name

upper lower units QGF

index Lambda-max (nm)

QGF-E (pc)

Lambda-max (nm)

128451 Alice-1 3730 3740 ft 6.6 414 21.5 374 128452 Alice-1 3740 3750 ft 8.6 407 11.9 374 128453 Alice-1 6096 ft 13.2 378 128455 Alice-1 6090 6100 ft 24.9 447 654.5 394 128456 Alice-1 6101 ft 43.7 377 128457 Alice-1 6100 6110 ft 14.8 445 746 365 128458 Alice-1 6150 6160 ft 10.4 418 331.9 379 128495 Alice-1 6170 6180 ft 21.2 451 385.5 376 128459 Alice-1 6180 6190 ft 12.2 428 179.9 374 128460 Alice-1 6675 6680 ft 1.8 410 21.5 378 128461 East Johnnys Creek-1 3610 3620 ft 8.7 401 3.9 308 128462 East Johnnys Creek-1 3620 3630 ft 8.9 400 2.2 305 128463 East Johnnys Creek-1 3680 3690 ft 7.1 401 1.4 315 128464 East Johnnys Creek-1 4680 4690 ft 3.5 400 5 305 128465 East Johnnys Creek-1 4690 4700 ft 3.6 397 4.1 311 128467 East Johnnys Creek-1 5050 5060 ft 4.2 401 302.2 374 128468 Erldunda-1 3080 3090 ft 4 399 12.7 361 128469 Erldunda-1 3090 3100 ft 7.9 401 7.2 310 128470 Erldunda-1 3830 3840 ft 1.5 382 2.1 356 128471 Erldunda-1 3840 3850 ft 1.2 373 2.9 358 128472 Erldunda-1 3850 3860 ft 1.1 365 2.4 357 128473 Erldunda-1 3990 4000 ft 2.1 380 12.8 362 128474 Erldunda-1 4000 4010 ft 2.3 383 10.8 359 128475 Erldunda-1 4740 4750 ft 5.1 388 30.8 366 128476 Erldunda-1 4750 4760 ft 7.4 402 28.3 356 128477 Finke-1 268.7 m 61.3 374 128478 Finke-1 298.1 m 16.3 372 128479 HighwayAnticline-1 1980 1990 ft 21.8 456 149.5 381 128480 HighwayAnticline-1 2010 2020 ft 14.7 449 47.1 371 128481 HighwayAnticline-1 2030 2040 ft 8 449 44.7 384 128482 HighwayAnticline-1 2050 2060 ft 14.2 414 184.4 382 128483 HighwayAnticline-1 2250 2260 ft 58.9 400 100.7 378 128486 Mount Winter-2A 168 m 1.4 357 128484 Mount Charlotte-1 2100 2110 ft 2.8 512 138.5 365 128488 Murphy-1 1098 1101 m 9.4 547 1.5 368 128489 Murphy-1 1101 1104 m 3.8 533 5 363 126715 Tempe Vale-1 354.9 m 1.4 361 6.5 329 126716 Tempe Vale-1 463.5 m 12.6 402 20.7 323 126717 Tempe Vale-1 591.4 m 0.9 355 6.2 332 126718 Tempe Vale-1 654.1 m 0.6 340 5.9 333 126719 Tempe Vale-1 690.7 m 1.8 455 6.5 331 126720 Tempe Vale-1 673.1 m 1.7 470 8.7 329 126721 Tempe Vale-1 709.6 m 3.8 462 7.4 331 126722 Tempe Vale-1 821.1 m nd nd nd nd 126723 Tent Hill-1 1104.8 m 0.9 366 10.8 330 126724 Tent Hill-1 1111.1 m 0.6 359 18.9 326 126725 Tent Hill-1 1203 m 1.2 360 19.5 329 126726 Tent Hill-1 1224.5 m 0.5 355 16.5 329 126727 Tent Hill-1 1234.8 m 1.5 397 28.9 328 126728 Tent Hill-1 1251 m 0.5 363 14.2 326 126729 Tent Hill-1 1260.1 m 1.5 400 31.5 328 126730 Tent Hill-1 1284.9 m 14.1 401 26 329 126731 Tent Hill-1 1307.8 m 10.3 399 17.8 324 126732 Tent Hill-1 1359.2 m 0.5 355 12.4 326 126733 Tent Hill-1 1373.3 m 5.8 392 13.8 324 126734 Undandita-1A 775.5 m 3.6 426 6.1 336 126735 Undandita-1A 777.5 m 3.1 459 6.3 330 126736 Undandita-1A 820 m 2.1 376 9.6 358

Table 3. Summary of QGF and QGF-E results on samples taken from Amadeus Basin wells.

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quiescence of the basin (since the Alice Springs Orogeny at least) is likely to have produced incipient generation events in shale units (ie, long-term constant low heating), thereby contributing to ‘oily’ spectra. Where possible, the ‘sandiest’ units were sampled from cuttings stored in the NTGS core facility in Alice Springs.

As the results are discussed individually in Liu et al (2004) and Marshall (in prep), we present only details pertinent to Finke-� in this section. This well is discussed in detail as it contains positive values for both QGF and GOI, has excellent well data (core), and a detailed geochemical analysis has been completed on oil in the core (see Gorter �984). The analysis of the core to ascertain the extent of any palaeo-oil accumulation is therefore much better constrained with data.

Due to the high calcite content of the samples taken for QGF and QGF-E within Finke-1, the fluorescence spectra was masked and, therefore, the results were not representative of oil. Equally, the presence of carbonate in the samples made them unsuitable for traditional GOI interpretation, as this technique was developed for clastic rocks. Instead, an alternative technique, termed FOI (Fields of view containing Oil Inclusions), was used. This technique was developed for rocks where oil inclusions occur in carbonate cements, rather than within framework grains, and typically yield higher values than GOI.

The uppermost three samples from Finke-� have FOI values of 85%, 47.6% and 7.4%, respectively (Table 4). Oil inclusions occur predominantly within healed fractures

crosscutting contiguous dolomite grains, and to a lesser extent, within dolomite cement in vugs associated with bitumen.

dISCuSSION

The application of offshore well (from Australia) calibration cutoffs to ascertain the relative likelihood of a hydrocarbon signature is debatable. The regional geology of the Amadeus Basin should be considered when applying logical cutoffs to the interpretation of migration pathways, current, residual and palaeo-oil zones and water zones. However, even the application of a 50% higher cutoff value still produces the same result – there is residual/palaeo-oil within the wells. Although the sampling was by no means dense downhole, the authors feel it is representative of the sampled formations.

As QGF-E measures the 2nd solvent extract from the reservoir grains after a pre-cleaning procedure, it shows primarily heavy aromatics, polars and asphaltenes adsorbed on the reservoir grains. Most heavy aromatics and polars would have a spectral peak at about 370 nm, when measured in DCM (Liu and Eadington 2005). The presence of asphaltenes would produce a rather broad spectrum, with the peak shift toward the long wavelength. Most of the spectra from the measured samples show a peak that is usually >355 nm, indicating a fairly light oil signature.

Oil compositions (eg API gravity) will affect the QGF spectra. Condensate oils tend to have QGF spectral peaks

Well name Depth (m)

Count Protocol

Total grains counted

Grains with oil inclusions

GOI (%)

FOI (%) Fluorescence colour QOB

blue white yellow Finke-1 253.3 R N/A N/A N/A 85 N/A N/A N/A N/A 267.2 R N/A N/A N/A 48 63 2 0 N/A 268.7 R N/A N/A N/A 78 8 6 4 N/A 298.1 R N/A N/A N/A 18 N/A N/A N/A N/A 340.2 R N/A N/A N/A 7 N/A N/A N/A N/A 400.4 R N/A N/A N/A 0 N/A N/A N/A N/A 425.6 R N/A N/A N/A 0 N/A N/A N/A N/A 456.8 R N/A N/A N/A 0 N/A N/A N/A N/A Temple Vale-1 463.5 C 19369 1 <0.1 N/A 0 0 1 0 654.1 C 3471 0 <0.1 N/A 0 0 0 0 690.7 C 8508 0 <0.1 N/A 0 0 0 0 709.6 C 2534 3 0.12 N/A 1 0 2 1 821.1 C 939 0 <0.1 N/A 0 0 0 0 Tent Hill-1 1104.8 C 1686 1 0.1 N/A 0 0 1 0 1203 C 8555 2 <0.1 N/A 1 0 1 0 1260.1 C 14073 0 <0.1 N/A 0 0 0 0 1284.9 C 6037 1 <0.1 N/A 0 0 1 0 1307.8 C 12542 0 <0.1 N/A 0 0 0 0 1359.2 C 1175 0 <0.1 N/A 0 0 0 0 1373.3 C 3142 0 <0.1 N/A 0 0 0 0 Undandita-1A 775.5 G 1287 289 22.5 N/A 4 61 273 0 820 C 17574 0 <0.1 N/A 0 0 0 0 Mount Winter-2 178.5 C 3018 2 0.1 N/A 2 0 0 0 Alice-1 1858.1 R N/A N/A N/A N/A 0 0 0 N/A 1858.7 R N/A N/A N/A N/A 0 0 0 N/A

Table 4. Results of GOI and FOI on samples taken from Amadeus Basin wells. R = Random scan of 100 fields of view; C = Continuous scan of �/3 of the slide GOI = Grains containing Oil Inclusions; FOI = Fields of view containing Oil Inclusions.

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towards the short wavelength (375–400 nm); normal/light oil would have spectral peaks around 400–425 nm and heavy oil would have spectra shift towards the longer wavelengths (>425 nm; Liu and Eadington 2005). Broadly, the results from samples trend towards a condensate/light-oil phase from the spectral peaks (Liu et al 2004, Marshall in prep).

Fluorescence sources of QGF signals are two fold, if the baseline fluorescence of the quartz grains are ignored. They are from oil inclusions and the surface-adsorbed hydrocarbons that remain on the grain surface after the QGF cleaning procedure. These two sources represent the presence of hydrocarbons in the pore space in the past. QGF-E measures the solvent-extractable hydrocarbons on the reservoir grain’s surface and thus, reflects the presence of a more recent hydrocarbon-charge event.

The results, even when applying a higher cutoff parameter, appear to show the presence of genuine palaeo-oil in all the samples. There is a small possibility of incipient generation causing an ‘artificial’ spectral response, but it is not assessed to be a significant risk. The age of the rocks, multiple diastrophic events and original source characteristics of part of the Amadeus Basin succession suggests it is entirely possible that results could be due to multiple charges of oil of different compositions (light/condensate phase) and origins.

Reflectance results generally indicate that oil moved through a stratigraphic unit penetrated in a well. They do not indicate whether the value is representative of a palaeo-oil column (former accumulation). Because the GOI technique directly measures the presence of oil in minute pore spaces, it should therefore reflect whether a well is located in a migration pathway, or if oil, formerly present, has leaked away.

The raw results of the GOI analyses from Amadeus Basin wells are shown in Table 4.

All the wells that had oil present in them on the basis of QGF and QGF-E, (except Finke-� and Undandita-�A), showed no GOI saturation. This confirms that although oil, probably sourced from the Neoproterozoic succession, was present, it was migrating (not accumulating), through the stratigraphy. This supports the suggestion that a number of previous wells (particularly the ones sampled), were drilled off structure.

It should be noted that a threshold of high oil saturation has, as yet, not been established for the FOI technique. However, under conditions of high oil saturation, such as those that accompany the presence of a stable oil column, most pores would be exposed to oil and a correspondingly high frequency of grains are likely to trap oil inclusions (high FOI >�5%). In the Dampier Sub-basin of Western Australia, FOI values of between 28% and 76% have been recorded in current oil zones (Lisk et al �996).

In the case of Tempe Vale-�, Tent Hill-� and Mount Winter-2A, samples were taken from the Ordovician succession (productive in the Amadeus Basin). Visual inspection of core from these wells shows ‘stringer’ oil staining, but not the style of staining expected from an oil column, indicating that, at these locations, the sampled Ordovician succession was a migration pathway and that the wells were drilled off structure. This hypothesis is confirmed by the results: QGF and QGF-E demonstrates that oil was

present (as does visual inspection), and GOI confirms that it had not accumulated at this location.

In Finke-1, a palaeo-oil zone is identified from 253.3 m (83� ft) to approximately 300 m and is untested above 253.3 m (Figure 4). The oil inclusions occur in dolomite and minor barite cementing penetrative fractures and vugs. The dolomite groundmass has sutured grain contacts with poor visible porosity and the observations are consistent with both intergranular porosity and intergranular oil saturation having been low. Structural analysis may contribute to determining the timing of the fractures and hence, of the oil migration/accumulation.

In Undandita-1A, a palaeo-oil zone was identified in one sample at 755.5 m, which is within a fault zone (Figure 5). However, at the grain scale, the occurrence of the inclusions does not indicate a structural control, as observed in the samples from Finke-� (Figure 6). The oil inclusions occur in intra-granular fractures, which is consistent with oil occupying intergranular porosity, and there is potential for a palaeo-oil zone to also have occurred in adjacent reservoir rocks. This would require investigation of reservoir samples from outside the zone of influence of the fault (not currently available).

The oil inclusions in the Finke and Johnnys Creek beds in Finke-� have predominantly blue and white fluorescence (Figure 6). The oil inclusions in the sample from Undandita-�A have predominantly yellow and white fluorescence (Figure 6). This suggests that the inclusion oils in each well have different attributes, probably due to different source units. Oil inclusions with blue fluorescence have a higher content of monoaromatic hydrocarbons and often higher API gravity than white- and yellow-fluorescing oil inclusions (Liu et al 2004, Stasiuk et al �997, Palmer et al �999).

CONCluSIONS

Fluid inclusions are formed in sandstone by: crystallisation of quartz to heal fractures during compaction; during crystallisation of overgrowths in response to pressure solution; and healing of fractures formed during periods of high earth stress associated with tectonism (see Liu and Fenton 2004). The long tectonic history of the Amadeus Basin has multiple events that might have led to the formation of fluid inclusions in sandstone, at each time, trapping ambient fluids that may have included oil in the pore spaces.

It is the authors interpretation that most exploration (wildcat) wells in the Amadeus Basin were drilled off structure, due to poor seismic/structural control. This is supported by the results of the study presented here, which indicate that oil has migrated through the stratigraphy, and towards(?) the actual high point of a structure.

Small numbers of oil inclusions were observed in samples from Tempe Vale-�, Tent Hill-�, and Mount Winter-2A. This indicates the presence of oil at low levels of saturation at the time the oil inclusions were formed. The GOI data do not exclude the presence of oil in these samples at times when fluid inclusions were not being formed. Visual inspections of core would suggest that the Ordovician section penetrated by these exploration wells is a migration pathway (visible oil streaks and stringers).

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Marshall et al

Additionally, where Neoproterozoic units were sampled (all wells except Tent Hill-�, Mount Winter-2A and Tempe Vale-�), the technique has shown that this oldest part of the stratigraphy has produced oil, as well as gas. The presence of gas, including sub-economic discoveries at Orange-�, Dingo-�, Ooraminna-� and Magee-�, is irrefutable evidence of active petroleum systems in the Neoproterozoic.

Finke-1 contains oil, as is confirmed by visual inspection, geochemistry (2 oil phases) and now by CSIRO fluid-history techniques. This (along with other data provided by a myriad of other authors), is almost incontrovertible evidence that the Neoproterozoic has produced oil and could potentially reservoir it.

The Neoproterozoic section of the Amadeus Basin is therefore prospective for both oil and gas. It follows that

20 40 60 80 100

FOI (%)

0 200

GR (API)Depth

(m)

250

300

350

400

450

238 m: Finke beds85%

48%78%

273 m: Johnnys Creek beds

18%

7%

399 m: Bitter Springs Fm<1%

<1%

<1%

A06-141.ai

Figure 4. Fields containing Oil Inclusions (FOI) plot for Finke-1. This profile is diagnostic of a palaeo-oil column.

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Petroleum systems in the Amadeus Basin: Were they all oil prone?

A06-142.ai

0 200

GR (API)

750

850

800

GOI (%)

20 2515105

Depth

(m)

23%

<0.1%

a b

c d

Ol

Ol

Ol

F

100 µm 100 µm

25 µm25 µm

A06-143.ai

Figure 6. (a–b) Equant blocky dolomite with oil inclusions (OI) trapped along healed penetrative fractures crosscutting grains in (a) transmitted and UV light and (b) dark background fluorescence mode and UV light. Finke-1, 253.3 m, 10 x magnification. (c–d) Trail of inclusions decorate a healed intra-granular fracture in a detrital quartz grain in (c) UV light and (d) dark background fluorescence mode and transmitted light. Undandita-1A, 775.5 m, 50 x magnification.

Figure 5. Grains containing Oil Inclusions (GOI) plot for Undandita-�A, showing a palaeo-oil accumulation. Note that one sample with a high value is unconstrained above, indicating that the column could be larger.

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Marshall et al

the petroleum systems defined by Marshall (2004), were all oil prone to a degree. Future exploration efforts should be directed towards revisiting sites of previous drilling (where off-structure), and sharpening models towards finding reservoir targets in some of the oldest productive (hydrocarbons flowed on DST) sedimentary rocks in Australia.

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