petrel sub-basin study 1995-1996 geohistory modelling

AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

PETREL SUB-BASIN STUDY

1995-1996

GEOHISTORY MODELLING

by

John M. Kennard

AGSO RECORD 1996/43

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DEPARTMENT OF PRIMARY INDUSTRIES AND ENERGY

Minister for Primary Industries and Energy: Hon. J. Anderson, M.P.Minister for Resources: Senator the Hon. W.R. ParerSecretary: Paul Barratt

. AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

Executive Director: Neil Williams

© Commonwealth of Australia 1996

ISSN: 1039-0073ISBN: 0 642 24976 8

This work is copyright. Apart from any fair dealings for the purposes of study, research,criticism or review, as permitted under the Copyright Act 1968, no part may be reproduced byany process without the written permission of the Executive Director, Australian GeologicalSurvey Organisation. Inquiries should be directed to the Principal Information Officer,Australian Geological Survey Organisation, GPO Box 378, Canberra, ACT 2601, Australia.

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PREFACE

AGSO's 1995-96 Petrel Sub-basin Study was undertaken within AGSO's Marine, Petroleum andSedimentary Resources Division (MPSR) as part of MPSR's North West Shelf Project. The study wasaimed at understanding the stratigraphic and structural development of the basin as a framework formore effective and efficient resource exploration. Specifically, the study aimed to:

• define the nature of the major basement elements underlying the Petrel Sub-basin and theirinfluence on the development of the basin through time,

• determine the nature and age of the events that have controlled the initiation, distribution andtectonic evolution of the basin;

• define the nature and age of the basin fill, and the processes that have controlled its deposition anddeformation; and, importantly,

• determine the factors controlling the development and distribution of the basin's petroleumsystems and occurrences.

This report is the final product of the geohistory modelling component of the study, using theWinBury V2 geohistory modelling package released by Paltech Pty Ltd. The report is intended for usein conjunction with the study's other products, notably the Well Folio, Organic Geochemistry Reportand Summary Report. Digital copy of the WinBury models and data files are also available forpurchase.

PRODUCTS AVAILABLE FROM THE PETREL SUB-BASIN STUDY

Summary Report (AGSO Record 1996/40, compiled by J.B. Colwell & J.M. Kennard).Summarises major results of the project.

Well Folio (by J.M. Kennard).Provides well composites for 31 key wells in the basin, as well as 6 well-wellcross-sections.

Map & Seismic Folio (by J.B. Colwell, J.E. Blevin & D.J. Wilson).Includes 24 time-structure and time-isopach maps as well as select interpreted seismic lines.

Digital Database of Seismic Interpretations.Covers — 8200 line km of AGSO deep- and conventional industry seismic data.

Petrel Stratigraphic Time Chart (by P.J. Jones et al.).Shows latest understanding of the Petrel Sub-basin stratigraphy and event historyagainst biozonations and AGSO's timescale.

Gravity Modelling Report (AGSO Record 1996/41, by J.B. Willcox)Details 2-D gravity modelling undertaken on 3 of the AGSO deep-seismic lines.

Organic Geochemistry Report (AGSO Record 1996142, by D. S. Edwards & R. E. Summons).Includes carbon isotope and biomarker analyses of oils, oil - source-rock correlations, and adigital source-rock and maturity database.

Geohistory Modelling Report (AGSO Record 1996/43, by J.M. Kennard).Details geohistory subsidence and thermal maturation modelling of 20 wells and 6pseudo-wells and hydrocarbon generation and expulsion models for 3 identified sourceintervals.

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•CONTENTS^

Page•

Abstract^ 1• Introduction and Methodology^ 3

Data Input^ 7• Data Output^ 9• Subsidence History^ 10

Phase A: Cambrian-Ordovician-?Silurian^ 10• Phase B: Frasnian - mid Toumaisian^ 10

Phase C: late Tournaisian - mid Visean^ 12• Phase D: late Visean - late Namurian^ 12• Phase E: latest Namurian- early Asselian^ 12

Phase F: late Asselian - Anisian^ 13• Phase G: Ladinian-Sinemurian (Fitzroy Movement and basin inversion)^13

Phase H: Sinemurian-Oxfordian^ 13• Phase I: late Oxfordian-Manstrichtian^ 13

• Phase J: Tertiary^ 14Thermal History^ 15

• Maturity Parameters^ 15Palaeo-Heatflow^ 16

• Source Rock Maturation History^ 19Mid-Milligans Source Unit^ 20Keyling Source Unit^ 39

• Hyland Bay Source Unit^ 55Conclusions^ 61

• Acknowledgments^ 62References^ 63

•

• Appendix A: WinBury Geohistory Modelling Flow Diagram^ 65Appendix B:^ 67

• Basin Stratigraphy Parameters^ 67Observed versus Computed Maturity, Heatflow & Tectonic Subsidence,^68

• Geohistory & Hydrocarbon Generation Plots for each well and pseudo-well• Appendix C: Kerogen Kinetic Data^ 113

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•LIST OF FIGURES^ page

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• Figure 1. Location of wells and pseudo-well sites used in this study.^ 5Figure 2. Stratigraphy of the Petrel Sub-basin, showing tectonic subsidence cycles and^6

• major tectonic events.Figure 3. Tectonic subsidence curves for all wells/pseudo-wells modelled in the Petrel^11

• Sub-basin, showing tectonic subsidence Phases A - J.

• Figure 4. Estimated amount of erosion of Permian Early Triassic sediments during the^14Fitzroy Movement.

• Figure 5. Present-day heatflow map for the Petrel Sub-basin.^ 17Figure 6. Modelled palaeo-heatflow curves for wells/pseudo-wells.^ 18

• Figure 7. Distribution of the mid-Milligans source rock unit.^ 21

• Figure 8. Bed maturity plot for the mid-Milligans source unit in modelled wells/^22pseudo-wells.

• Figure 9. Present-day bed maturity map for the mid-Milligans source unit.^22Figure 10. Hydrocarbon generation plots for the mid-Milligans source unit in^25

• modelled wells/pseudo-wells.

•Figure 11. Bed maturity map of the mid-Milligans source unit at the time of deposition^36of the regional Treachery Shale seal (296 Ma).

• Figure 12. Comparative hydrocarbon generation plots for the mid-Milligans source^37rocks in the depocentre north of the Turtle-Barnett High (pseudo-well site FID16-sp400)

• and the Cambridge Trough south of the Turtle-Barnett High (pseudo-well site CB81-11a).

0^Figure 13. Distribution of the Keyling source rock unit..^ 40Figure 14. Bed maturity plot for the Keyling source unit in modelled wells/pseudo-wells. 41

• Figure 15. Present-day bed maturity map for the Keyling source unit.^41Figure 16. Hydrocarbon generation plots for the Keyling source unit assuming little or^43

• no net effective thicknesses of high-quality coaly shales.Figure 17. Hydrocarbon generation plots for the Keyling source unit assuming 10-15 m^49

• (i.e., 5 % net TOC), and 40-60 m (i.e., 10 % net TOC) net effective thicknesses of

• high-quality coaly shales.Figure 18. Distribution of the Hyland Bay source rock unit.^ 57

• Figure 19. Bed maturity plot for the Hyland Bay source unit in modelled wells/^58pseudo-wells.

• Figure 20. Present-day bed maturity map for the Hyland Bay source unit.^58

• Figure 21 Hydrocarbon generation plots for the Hyland Bay source unit.^59

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• LIST OF TABLES

• Table 1. Wells analysed in Petrel Sub-basin project.^ 4Table 2. Stabilised bottom hole temperatures of wells modelled in this study.^9

• Table 3. Wells/pseudo-wells with modelled source rock units.^ 19

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•^© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^

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I 1•• Abstract

• Geohistory models of 20 wells and 6 pseudo-well sites in the Petrel Sub-basin are presented to

•elucidate the complex multi-phase subsidence/uplift history of the basin, and to determine thelikely timing of hydrocarbon generation and expulsion from three identified source rock

• intervals that underpin the basins proven petroleum systems. The models are based onsequence stratigraphic units (second and third order sequences) interpreted to depth of

• basement, and utilise a new regional understanding of the stratigraphic and structuraldevelopment of the basin obtained during AGSO's 1995-1996 Petrel Sub-basin Study.

•

• Subsidence models indicate that nine distinct tectonic subsidence phases have controlled theregional basin-fill architecture and stratigraphic history of the Petrel Sub-basin. A phase of

• Cambrian-Ordovician subsidence (Phase A) was initiated by crustal extension and extrusionof tholeiitic basalts in the Early Cambrian. The major Petrel rift structure was initiated in the

• late Givetian - Frasnian, and this "syn-rift" extensional phase (Phase B) was terminated by

• widespread uplift and erosion in the mid Tournaisian. Subsequent tectonic phases (Phases C,D, E and F) appear to have been controlled by re-newed upper and/or lower crustal extension

• and thermal sag. Compressive tectonism in the Middle Triassic - Early Jurassic (FitzroyMovement) resulted in widespread uplift and erosion of the flanks of the Petrel Sub-basin, and

• the formation of inversion anticlines in the central Petrel Deep (Phase G). This compressive

• basin phase was followed by a phase of minimal net tectonic subsidence throughout most ofthe Jurassic (Phase H), and two subsidence pulses in the late Oxfordian and Valanginian

• (jointly Phase I) correlate with the Argo and Gascoyne spreading events along the outermargin of the North West Shelf. A final subsidence phase in the Tertiary (Phase J) is poorly411^constrained in the Petrel Sub-basin.

• Maturation models of three identified source rock units in the Petrel Sub-basin (mid• Milligans, Keyling and Hyland Bay source units) provide a much improved understanding of

the maturation, expulsion, migration and trapping history of hydrocarbons discovered in the• basin, and provides new insights into the basin's future exploration potential.

• Composite biodegraded and non-biodegraded oils recovered in the Turtle and Barnett wells• were probably charged by hydrocarbons expelled from the mid-Milligans source unit within

depocentres to the north and south of the Turtle-Barnett High. Expulsion from the northern• source kitchen probably occurred during the mid Carboniferous (Namurian), and this oil was

biodegraded as it migrated into shallow, oxidised, fluvial-deltaic reservoirs on the Turtle-• Barnett High. Expulsion from the southern source kitchen (Cambridge Trough) probably

• occurred during the Early Permian following the deposition of the Treachery Shale whichforms a regional seal for hydrocarbons sourced from the Milligans Formation. This oil

• accumulated in the now more deeply buried stacked reservoirs across the Turtle-Barnett High,and was sealed from oxidising groundwaters by the Treachery Shale. Subsequent fault

• reactivation (probably during the Fitzroy Movement) resulted in partial breach of this seal,

• and a second phase of oxidation and biodegradation of the shallower oil accumulations.

• Untested stratigraphic traps within the Cambridge Trough were probably charged by oilexpelled from the mid-Milligans source unit during the Early Permian, and these

• accumulations are unlikely to be biodegraded since the regional Treachery Shale seal was

• deposited prior to the expulsion of oil.

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Oil shows in the recently drilled Waggon Creek-1 well were probably expelled during thePermian from the mid-Milligans source unit in the central Carlton Sub-basin. These oils couldsource onlapping turbiditic sand pinchouts against the basal Milligans Supersequenceboundary on the flanks of the Carlton Sub-basin, as well as underlying reefal plays in theNingbing Supersequence.

The Tern Gas Field and the Petrel Gas-Condensate Field were probably charged by gasexpelled from the Keyling and/or Hyland Bay source units in the outer and central Petrel Deepduring the Late Triassic-Cretaceous (Keyling source) and Tertiary (Hyland Bay source).Shales within the Keyling Supersequence also have the potential to generate minor amounts ofoil; in the outer Petrel Deep, this oil was probably expelled during the Late Permian, prior tostructuring and trap formation in the Middle Triassic - Early Jurassic (Fitzroy Movement). Inthe central Petrel Deep, this oil was probably expelled during and shortly after structuring, andmay have contributed to the condensate recovered at the Petrel Field. On the shallowersouthern flank of the Petrel Deep, minor amounts of oil were probably expelled during theCretaceous and Tertiary.

High-quality, immature to marginally mature, oil-prone, coaly shale source rocks are known tooccur in the Kinmore-1 and Flat Top-1 wells, but maturation models suggest that they haveexpelled little or no hydrocarbons in these wells. If these high-quality source rocks extend todeeper portions of the Petrel Deep, they probably expelled significant quantities of oil and gasduring the Early Triassic, prior to the main phase of structuring and trap formation during theFitzroy Movement. Thus any stratigraphic or combined structural-stratigraphic traps ofPermian-Early Triassic age on the flanks of the Petrel Deep may have been charged by oilexpelled from the Keyling coaly shale and shale facies in the Petrel Deep during the EarlyTriassic.

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• Introduction and Methodology

• This record comprises geohistory models for 20 wells and 6 pseudo-wells (sites based onseismic interpretations) in the Petrel Sub-basin (Table 1; Fig. 1). The wells are modelled using

• the WinBury V2 burial and thermal geohistory modelling package for Windows mi produced by

•Paltech Pty. Ltd. Wells drilled on and adjacent to inferred and proven salt diapirs (Bougainville-1, Curlew-1, Gull-1, Kinmore-1, Matilda-1, Pelican Island-1 & Sandpiper-1) were not modelled

• due to stratigraphic disruption and complications involving thermal anomalies. However,stratigraphic and geochemical data from these wells were used to constrain data input for

• adjacent wells and pseudo-wells.

• The wells are modelled on the basis of sequence stratigraphic units (second-order• supersequences and third-order sequences) interpreted from well-log and seismic data as

summarised on the composite well logs in the AGSO Petrel Sub-basin Well Folio (Kennard,• 1996). Full descriptions of the sequences are given in the AGSO Petrel Sub-basin Summary

Report (Colwell & Kennard, 1996, Chapter 4), and their stratigraphic relationships and age aresummarised in Figure 2. Details of biozone and stratigraphic age relationships are presented on

• the Petrel Sub-basin Stratigraphic Time Chart (Jones et al., 1996).

• All wells are modelled to basement below TD based on seismic stratigraphic interpretations (seePetrel Sub-basin Map & Seismic Folio, Colwell et al., 1996). Additional well data werecompiled from well completion reports, composite well logs, and unpublished company and

• laboratory reports compiled during the AGSO Petrel Sub-basin Project.

• The methodology used for WinBury geohistory modelling is summarised in Appendix A.Extensive use has been made of the comprehensive on-line help system provided by WinBury

• for all data input and manipulation, including on-line geohistory theory and illustrations which

• assist modelling and interpretation of the data.

• In order to ensure consistent subsidence and thermal models within similar structural andtectonic provinces, the 26 wells and pseudo-wells have been grouped into 6 provinces (Fig. 1):

• 1) Petrel Deep, 2) Lacrosse Terrace, 3) Berkley Platform, Cambridge High and Turtle-Barnett

•High, 4) Cambridge Trough, Keep Inlet Sub-basin and Kulshill Terrace, 5) Carlton Sub-basin,and 6) northeastern flank of the Petrel Sub-basin.

•All geohistory models and data files used for this study are available in digital format; a copy of

• the WinBury software is required to access this digital data.

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PETREL SUB-BASIN WELL ANALYSIS

Well Name Digital Logs (Wiltshire) Stratlog Geohistory ModelComposite WinBury

Barnett-1 Y Y -Barnett-2 Y Y YBerkley-1 Y Y YBillawock-1 Y Not for Release Not for ReleaseBonaparte-1 Y Y YBonaparte-2 Y Y YBougainville-1 Y Y (Salt diapir)Cambridge-1 Y Y YCurlew -1 Y Y (Salt diapir)Fishburn-1 Y Not for Release Not for ReleaseFlat Top-1 Y Y YFrigate-1 Y Y -Garimala-1 Y Y YGull-1 Y Y (Salt diapir)Keep River-1 Y Y YKingfisher- 1 Not Available Not for Release Not for ReleaseKhunore-1 Y Y (Salt diapir)Kulshill-1 Y Y YLacrosse-1 Y Y YLesueur-1 Y Y YMatilda-1 Y Y (near Salt diapir)Ningbing-1 Y Y -Pelican Island-1 Y Y (Salt diapir)Penguin-1 Y Y YPetrel-1 Y Y -Petrel-1A Y Y YPetrel-2 Y Y YSandpiper-1 Y Y (Salt diapir)Skull-1 Y YSpirit Hill-1 Not Available YSunbird-1 Not Available Not for Release Not for ReleaseTern-1 Y Y YTurtle-1 Y YTurtle-2 y Y YWeaber-2,2A Y YAGS0/1-SP3400 (Outboard of Lacrosse) YAGS0/5-SP2800 (midway Kinmore -Bougainville) YAGS0/7-SP1100 (Near Gull- 1) YCB81-11-SP535 (Cambridge Trough) YHD16-SP400 (North of Turtle-Barnett High) YHD16-SP1050 (North of Turtle-Barnett High) Y

Table 1. Wells analysed in Petrel Sub-basin project. Synthetic well locations shown in italics.

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Curlew 1

fib Gull 1

–12°

AGS017-SP1100^N.

5

.M Salt diapir } Major °basin forming" faults

± Anticline

--t— Axis of Petrel Deep

Hinge

-*Tem 2 Petroleum exploration well*Gull 1 Petroleum exploration well used

in this studyC1381 -11a0^Pseudo-well site used for

maturation modellingNSF-1002•^Mineral exploration hole

Precambrian basement

Figure 1. Location of wells and pseudo-well sites used in this study.

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AGE(Ma)

PERIOD EPOCH SEQUENCE^SEISMICHORIZON

TECTONICSUBSIDENCE

PHASEBASINPHASE EVENT

_ QUATERNARY PlioceneMiocene

20 -_

TERTIARYOligocene Undifferentiated Tertiary

Jand Quaternary40-

_Eocene

60- PaleoceneTE_ Erosion

80- Late_

Sag dominatedlog- Bathurst Island

_CRETACEOUS

I120- Early

_

140 BI "Gascoyne Breakup"Flamingo

- Late FL "Argo Breakup"160 -

- JURASSIC Middle Plover H180 -

Early PV200 - <— Erosion

- Malita

220 - Late "Fitzroy Movement"MA_ TRIASSIC

Middle240- Cape Londonderry

Early CLMount Goodwin

Local uplift

260- Late — H4Initial-

Hyland Bay— H5

al compressionPERMIAN

280-Early Fossil Head

- FHKeyling

300- .•Treachery^TS

_ Penns. Kuriyippi Onset of glaciationKY

Point Spring320-

- CARBONIFER. PS Local uplift and erosion

Miss.Tanmurra^Ti (C-T-B area)

340- Milligans C

-ML

Langfield Uplift, erosion and faulting

360- Late Bonaparte^Ningbing

-

380-_

CiTrift o• Ination of major Petrelupper crustal extension (= Pillars)

DEVONIANMiddle—

BASE,

400 - Early)? Compression (="Prices Creek

Late '^SALT Movement")

420 - SILURIAN Early_aao -

Late_

s Initiation and

ORDOVICIAN400- A subsidenceof Protobasin

Early480-

Late500-

Middle Carlton Group

- CAMBRIAN

520- Early Antrim Plateau VolcanicsBasin initiation^23/0A/760

Figure 2. Stratigraphy of the Petrel Sub-basin, showing tectonic subsidence cycles and majortectonic events.


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• Data Input

• Specific aspects of critical data input are discussed below.

• Global Lookup Paths/Tables • Chronostratigraphy: Chronostratigraphic ages of sequences are based on the AGSO Petrel

Sub-basin Stratigraphic Time Chart (Jones et al, 1996) and are summarised in Appendix B.• Sea Level: The AGSO 1995 long term sea-level curve has been used for the Mesozoic. A

Palaeozoic sea-level curve has not been entered since the available Exxon-derived curve• (Greenlee & Lehmann, 1993) has not yet been calibrated with the AGSO Timescale at other

• than Period level. Palaeozoic sea-level is thus assumed to be constant at the present day level.Maturity Conversion: Thermal Alteration Index (TAI) and Spore Colour Index (SCI) values

• have been converted to equivalent vitrinite reflectance values using an in-house correlation ofmaturation indices (C. Foster, AGSO, unpubl., March 1996). Tmax values (from Rock-Eva!

• pyrolysis) have been converted to equivalent vitrinite reflectance values using the WinBury

• maturity conversion files. Conodont Colour Alteration Index (CAI) values have beenconverted to equivalent vitrinite reflectance values following Epstein et al. (1977, fig. 11).

• Lithology Definitions: The default WinBury Lithologic Parameter File, which defines thecompaction rate constants, matrix conductivity and density values, was used.

• Kinetic Definitions: Kinetic data for all modelled source rock units were defined by kerogen

• kinetic analyses (see Appendix C).Options: All data were converted to the following standard units: Depth-metres, Heatflow-

• milliwatts, Temperature-centigrade.Heat Flow Mode - Relative to present day value.

• Processing Option - Sweeney (easy Ro).

• Well Header Data• Present Surface Temperature: 27°C was used for all wells based on temperature

measurements made in the region during water-column gas sampling "sniffer" surveys• (Bishop et al., 1992; Bickford et al., 1992) and an Ocean-Bottom. Seismometer survey (pers.

• comm., Chao Shing Lee, AGSO, March 1996).Bottom Hole Temperature: Corrected bottom hole temperatures (based on Homer plots)

• have been used where available (e.g., well completion reports), or calculated using the Homerplot facility within WinBury. In those wells where there was insufficient temperature and/or

• circulation time data to construct Homer plots, the maximum measured log temperature plusup to 10% (depending on time since circulation, and available drill-stem/formation test

• temperature data) has been used. In the event that reliable bottom-hole, log or drill-• stem/formation test temperatures were not available, temperature data were estimated from

adjacent wells (within the same structural element and with comparable stratigraphic• successions) such that the calculated present-day heatflows of comparable wells are similar.

The stabilised bottom hole temperatures entered for each well are shown in Table 2.• Basement Depth: Interpreted from seismic data if below TD (see Map and Seismic Folio,• Colwell et al., 1996).

• Horizon DataStratigraphic Unit, Depth to top of Unit: Based on sequences and sequence boundaries as •

• shown on composite well logs (see Well Folio, Kennard, 1996).• Age: Ages of sequences based on AGSO Petrel Sub-basin Time Chart (Jones et al., 1996).

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8 •Hiatuses/Unconformities: Estimations of the thickness, lithology and age of eroded sectionsand hiatuses were based on understandings gained from regional seismic stratigraphicinterpretations and well-well cross-sections. For this purpose, hiatuses and unconformitieswere initially assessed for wells within a common structural province, and were modifiedwhere necessary to achieve the best match between modelled and observed maturity data.Min/Max Modelled Water Depth: Estimates of palaeo-water depth at top of sequencesbased on lithofacies, palaeoenvironmental interpretations, and sequence stratigraphicconcepts.Palaeo Sea Bed Temperature: Estimated from lithofacies, palaeoclimate and palaeo-latitudeposition of Petrel Sub-basin (see Appendix B).Heatflow: WinBury calculates present-day heatflows from observed/estimated stabilisedbottom-hole temperatures, the thermal conductivity of the well lithologies, and the present-daysurface temperature. Palaeo-heatflows were modelled by a combination of two approaches;uniformitarian and graphical. In the uniformitarian approach, present-day heatflows forspecific tectonic settings (e.g., rifts, post-rift passive margins) were used to guide estimates ofheatflows for sequences deposited in similar tectonic settings. In the graphical approach,theoretical heatflow curves in basins formed by differing amounts of crustal extension wereused as a guide to model palaeo-heatflow in individual wells and groups of comparable wells.Based on the present-day heatflow, palaeo-tectonic setting and tectonic subsidence curve foreach well, an appropriate "bell-shaped" cool-down curve was modelled for each well. Thispalaeo-heatflow model was validated, and re-modelled as necessary, against observedmaturity data (see "Palaeo-Heatflow" section for more details).Lithology Data: Lithological data was based on well completion reports and composite welllogs. It is important to note that the default Lithological Parameter file is based on pure end-member 'matrix lithologies'. Thus a 'sandstone' is a pure quartz arenite with a density of 2.65gm/cc, conductivity of 16 mcalkm sec °C, initial porosity of 40 %, and a porosity/depth factorof 0.40. A specific sandstone with a variety of framework grain types, and minor interstitialargillaceous material (inter-framework matrix) should be entered as sandstone-shale mixture(eg., sandstone 80 %, shale 20 %); similarly a calcareous siltstone with silt-sized quartz grainsand interstitial calcareous and argillaceous material must be entered as a sandstone-shale-limestone mixture. It was found that the gamma log can generally be used as a guide todetermine the proportion of 'matrix lithologies'.Kerogen Data: Kerogen kinetic data for all modelled source beds are given in Appendix C.Variable Beds: Halokinetic movements, such as salt diapirs, have not been modelled. Wellsdrilled on and adjacent to salt diapirs have not been modelled.

Observed Maturity DataObserved maturity data are used to calibrate the well models by constraining the maturityprofile predicted by the model. Six maturity parameters have been used: Vitrinite reflectance,Fluorescence Alteration of Multiple Macerals, Thermal Alteration Index, Spore Colour Index,Tmax (from Rock-Eval pyrolysis) and Conodont Colour Alteration Index. These data wereobtained from the compilation presented by Edwards & Summons (1996).

Observed Temperature DataMaximum recorded log temperatures, drill-stem/formation test temperature data and stabilisedbottom hole temperatures (based on Homer plots) have been used. The source of temperaturedata is identified in an associated flag table.

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Observed Porosity and Thermal Conductivity DataPorosity and thermal conductivity data were not entered for any wells; the WinBury programuses default values for these parameters based on lithological data.

Fluid Inclusion and Fission Track DataFluid inclusion and fission track data were not available for any of the wells studied.

Data Output

For each well and pseudo-well the following plots are presented (see Appendix B):• Observed versus Computed Maturity Plot• Heatflow and Tectonic Subsidence Plot• Geohistory plot

Bed Maturity Plots, Bed Maturity Maps and Hydrocarbon Generation Plots for each sourcerock unit are presented as separate text figures.

Well Name^

Bottom Hole^DepthTemperature °C^in

Barnett-2^ 102^ 2811

Berkley-1^ 56^ 874

Billawock-1^ 78^ 1734

Bonaparte-1^ 115^ 3050

Bonaparte-2^ 98^ 2136

Cambridge-1^ 86^ 2224

Fishburn-1^ 122.5^ 2865

Flat Top-1^ 108^ 2173

Garimala-1^ 127^ 2553

Keep River-1^ 190^ 4760

Kingfisher-1^ 110^ 3253

Kulshill-1^ 155^ 4394

Lacrosse-1^ 105^ 3054

Lesueur-1^ 116.5^ 3590

Penguin-1^ 107^ 2754

Petrel-2^ 164^ 4760

Sunbird-1^ 117.5^ 3400

Tern-1^ 154^ 4352

Turtle-2^ 97^ 2760

Table 2. Stabilised bottom hole temperatures of wells modelled in this study.


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Subsidence History

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Tectonic subsidence models indicate that the Petrel Sub-basin has undergone a complex,multi-phase, tectonic history (Fig. 3). Nine distinct subsidence phases are evident in mostwells/pseudo-wells (Phases B to J), although Phase E is evident only in the outer portion ofthe basin (e.g., Petrel-1A, 2, Fishburn-1, Tern-1 and Penguin-1). Several of these phases arecharacterised by an initial rapid subsidence (or local uplift) stage, followed by a moreprolonged stage of waning subsidence, a pattern consistent with extension and subsequentthermal sag (McKenzie, 1978). Some of these extension-sag cycles were interrupted bysubsequent events, such that the initial rapid mechanical subsidence stage of a newextensional-sag cycle has been superimposed on, and thereby masks, the slow thermalsubsidence stage of the preceding phase.

Total tectonic subsidence ranges from 7-9 km for wells in the outer and central Petrel Deep(Petrel-1A, 2, pseudo-well site ASGO Line 7-sp1100), to about 5 km in the inner Petrel Deep(Fishburn-1, Tern-1, Penguin-1), about 2-3 km in the Carlton Sub-basin, Cambridge Trough,Keep Inlet Sub-basin, Kulshill and Lacrosse Terraces, and less than 2 km on the Turtle-Barnett and Cambridge Highs and Eastern Ramp margin. Given that the maximum thermalsubsidence of the present ocean basins is about 6 km, a single rift event and subsequentthermal sag cannot explain the observed amount of tectonic subsidence in the Petrel Sub-basin. A full discussion of other possible subsidence mechanisms is presented by Baxter(1996).

Phase A: Cambrian -?Silurian

An initial, "pre-rift" Cambrian-?Silurian tectonic phase is thought to represent initialsubsidence of the basin following extension and extrusion of tholeiitic basalts of the AntrimPlateau Volcanics in the Early Cambrian. However, these sediments have not been intersectedin exploration wells, and the subsidence pattern during this phase has not been modelled inthis study. This phase was terminated by gentle folding, regional uplift and erosion prior toinitiation of the Late Devonian Petrel Rift.

Phase B: Frasnian - mid Tournaisian

This phase is characterised by rapid subsidence following the initiation of the Petrel Rift at theend of the Givetian. More detailed characterisation of this phase is only possible in wells inthe onshore Carlton Sub-basin, and to a lesser extent Kulshill-1, where tectonic subsidencecurves indicate very rapid initial subsidence during deposition of the CockatooSupersequence, and decreasing subsidence rates during deposition of the Ningbing andLangfield Supersequences (Fig. 3). Seismic data show clear evidence of large growth faultsand rotated fault blocks during this phase (see AGSO Lines 100/1, 2 & 3, Seismic and MapFolio, enclosures 1-3). Similarly, the thickening of coarse elastic facies of the CockatooSupersequence against the eastern fault margin of the Carlton Sub-basin (Mory & Beere,1988, fig. 52) indicates active fault movement at the beginning of this phase. Up to 2.5 km oftectonic subsidence occurred during this phase which appears to have affected all areas of thePetrel Sub-basin.

This "syn-rift" extensional phase was terminated by widespread uplift and erosion in the midTournaisian, especially across the Cambridge and Turtle-Barnett Highs. Although the amount •

••


Thr

A

Carlton SB •CT-Keep Inlet SB •C-T-B High •Lacrosse Terrace •Petrel Deep •E Ramp Margin •

Tectonic Subsidence Phases A-J

Stripped Basement vs Time

II*R

1111^41111 TIME (vid)

14....ftworm" ^imam lift%

12

of uplift and erosion is difficult to gauge in most wells, clear evidence of about 1500 m oftilting, uplift and erosion of the Bonaparte Megasequence beneath the MilligansSupersequence is apparent on seismic data near Cambridge-1 (e.g., Seismic line CB80-25).Maturation modelling of this well is also consistent with about 1500 m erosion at the baseMilligans unconformity (Appendix B, Cambridge-1 maturity plot).

Phase C: late Tournaisian - mid Visean

This subsidence phase corresponds to deposition of the Milligans Supersequence, and ischaracterised by rapid subsidence of the Carlton Sub-basin, Cambridge Trough, Keep InletSub-basin and Kulshill Terrace (Fig. 3). In these areas, modelling indicates about 500-1000 mtectonic subsidence during this phase, whereas subsidence was more limited across theCambridge and Turtle-Barnett Highs (about 200-300 m), and was even less on the LacrosseTerrace and in the Petrel Deep.

Owing to poor chronostratigraphic subdivision of the Milligans Supersequence, it is difficultto determine the style (and hence the origin) of subsidence during this phase. However, thefact that the Milligans Supersequence comprises a major transgressive-regressive cyclesuggests initial rapid subsidence (transgressive half-cycle) followed by slower subsidence(regressive half-cycle). Isopachs of the Milligans Supersequence (Map & Seismic Folio, plate10) indicate that deposition of these sediments was greatest towards the centre of the CarltonSub-basin and Cambridge Trough, and within lobes in the southernmost Petrel Deep. Thesesediments thin towards the faulted margins of the depocentres, suggesting little or no faultmovement during Milligans deposition. This subsidence phase was probably largelycontrolled by thermal subsidence following crustal extension during phase B.

Phase D: late Visean - late Namurian, andPhase E: latest Namurian - early Asselian

In all areas except the Petrel Deep, a typical extension-sag phase (Phase D plus E) isrecognised for the late Visean - early Asselian succession which incorporates the Tanmurra,Point Spring and Kuriyippi Supersequences. An initial stage of rapid subsidence duringdeposition of the Tanmurra Supersequence was controlled by renewed upper crustal extensionas indicated by (?oblique or strike-slip) faulting along the southwest margin of the Petrel Deep(see AGSO Lines 1, 2, and 3, Map & Seismic Folio). This extension stage was followed by amore prolonged sag stage characterised by exponential waning subsidence.

Tectonic subsidence during this phase was greatest in the Petrel Deep (1200-2400 m tectonicsubsidence during phase D), and progressively decreases in more inboard areas (800-1000 mduring Phase D-E on the Lacrosse and Kulshill Terraces, 300-500 in on the northeastern flank,Cambridge-Turtle-Barnett Highs and Cambridge Trough, and less than 200 m in the CaltonSub-basin).

Subsidence Phase E is only recognised in the Petrel Deep (e.g., Petrel-1A, 2, Fishburn-1,Tern-1 and Penguin-1, and pseudo-well sites AGS0/5-sp2800, AGS0/7-sp1100; Fig. 3), andcorresponds to deposition of the Kuriyippi Supersequence. In these wells this phase is markedby a rapid increase in tectonic subsidence, especially in more outboard positions (e.g., Petrel-

tr)

^

^1A, 2, and pseudo-well site AGS0/7-sp1100). This phase may be controlled by LateCarboniferous (latest Namurian) NW-SE extension in the Malita Graben which may signal the

so0

initiation of the Westralian Superbasin (Etheridge & O'Brien, 1994). Flexural isostatic0.ce ^ © AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^

13

modelling indicates that NW-SE extension centred on an inferred major NE-SW fault in thevicinity of Gull- 1 may have controlled the rapid increase in subsidence in the Petrel Deepduring this phase (Baxter, 1996; see Colwell & Kennard, 1996, chapter 5), but any such faultis poorly imaged on existing deep seismic data. Mory & Beere (1988) also recognised localactive faulting in the onshore portion of the basin at this time, based on the recognition of fan-delta facies within outcrops of the Keep Inlet Formation adjacent to uplifted fault blocks.

Phase F: late Asselian - Anisian

This phase incorporates the Treachery, Keyling, Fossil Head - Hyland Bay and Mt Goodwin -Cape Londonderry Supersequences. It is characterised by rapid early subsidence duringdeposition of the Treachery Sequence, followed by a relatively prolonged stage (about 50 Ma.)of waning subsidence (Fig. 3). Tectonic subsidence during this phase ranges from 800-1200 min the Petrel Deep, decreasing to about 400-800 m in more inboard areas. In the Carlton Sub-basin, virtually all of the sediments deposited during this phase were subsequently strippedduring the Fitzroy Movement, but modelling of maturation profiles for wells in this areasuggest about 200 m tectonic subsidence during this phase.

Tectonic subsidence decreases to zero near the end of this phase, and many wells show minoruplift (less than 100 m) at the end of this phase. This apparent uplift probably indicates thefirst pulses of the Fitzroy Movement, but since much of the younger sediments of this phasewere subsequently stripped during the Fitzroy Movement, the thickness of these erodedsediments may have been underestimated (the modelled thicknesses of eroded sediments arebased on the minimal amount required to match observed maturity profiles).

The rapid and then waning subsidence pattern of this phase is consistent with renewedextension and subsequent thermal sag, but there is no clear seismic evidence of significantupper crustal fault movement during this phase. Extension during this phase may thus havebeen partitioned within the lower crust beneath the Petrel Sub-basin.

This phase of tectonic subsidence was terminated by uplift and erosion associated with theFitzroy Movement, the peak of which occurred during the late Middle Triassic (Ladinian).

Phase G: Ladinian-Sinemurian (Fitzroy Movement and basin inversion)

This phase incorporates uplift and erosion during the Fitzroy Movement, and deposition of the"syn-tectonic" Manta Supersequence (Fig. 3). This compressive movement affected all areasof the Petrel Sub-basin, and a substantial thickness of Permian and Early Triassic sedimentwas eroded from the southern and southwestern flanks of the sub-basin at this time (Fig. 4;400-800 m on the Berkley Platform, Cambridge and Turtle-Barnett Highs, Cambridge Troughand Keep Inlet Sub-basin, and about 1000 m on the western flank of the Carlton Sub-basin).Large-scale inversion anticlines developed within the Petrel Deep at this time, and form trapsfor the Petrel and Tern Gas Fields.

Phase H: Sinemurian-Oxfordian

This phase of minimal net tectonic subsidence incorporates the Plover Supersequence, andappears to be uniformly expressed throughout all provinces of the Petrel Sub-basin (Fig. 3).


•— 200— Contour of estimated erosion (m)

(400)Êstimated erosion in well (m) •t22' 130°128

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•••••••••••••••

••

14^ •Phase I: late Oxfordian-Maastrichtian

This phase incorporates the Flamingo and Bathurst Island Supersequences, and ischaracterised by a moderate net increase in tectonic subsidence during the late Oxfordian tolate Berriasian, followed by net minimal subsidence throughout the remainder of theCretaceous (generally less than 100 m total net tectonic subsidence; Fig. 3). Detailed analysisof the subsidence history during this phase was not attempted during this study. Nevertheless,sequence stratigraphic concepts suggest two distinct pulses of rapid subsidence: the first in thelate Oxfordian-Kimmeridgian corresponding to widespread transgression at the base of theFrigate Shale, and the second in the Valanginian corresponding to widespread transgression atthe base of the very condensed Darwin Shale section. These pulses are correlated with theArgo and Gascoyne break-up events. This phase was terminated by regional uplift and channelincision at the base of the Tertiary Supersequence (e.g., ASGO Line 5, Map & Seismic Folio).

Phase J: Tertiary^ •

The pattern of subsidence during this phase is not known due to inadequatechronostratigraphic subdivision of Tertiary strata in the basin. About 100-200 m tectonicsubsidence occurred in all areas during this phase (Fig. 3).

••••

•••

••

Figure 4. Estimated amount of erosion of Permian - Early Triassic sediments during theFitzroy Movement. Estimates based on minimal amount of eroded section required to modelobserved maturity profiles in each well.


•••

15

Thermal History

Two critical factors in modelling the thermal history of the wells are:• the assessment and selection of reliable maturity parameters, and• the establishment of palaeo-heatflow curves.

' Maturity Parameters

Six maturity parameters were used in this study: Vitrinite reflectance (Rv), FluorescenceAlteration of Multiple Macerals (FAMM), Thermal Alteration Index (TM), Spore ColourIndex (SCI), Tmax and Conodont Colour Alteration Index (CAI). These data were obtainedfrom the database compiled by Edwards & Summons (1996).

Plots of observed maturity parameters versus depth for each well (Appendix B) commonlyindicate that some parameters are internally inconsistent (that is, they do not show an expectedprogressive increase in maturity down the well) and highly variable, or that the maturity valueof one parameter contradicts that indicated by other parameters. Rv, FAMM, CM and, to alesser degree, TM were generally found to be the most consistent and reliable maturityparameters in the studied wells.

Vitrinite Reflectance: Rv values were generally the most widely available and reliablematurity parameter in the studied wells. Spurious data attributed to measurement of maceralsother than vitrinite was excluded (see Edwards & Summons, 1996), but several wells showdisparate values which could be attributed to either oxidation (in the laboratory or in nature),oil staining of the organic matter, and contamination by cavings. In some wells, disparate Rvvalues are clearly attributed to different analytical laboratories (e.g., Keep River-1, Petrel-2).The most consistent Rv data comes from the most recently drilled wells (e.g., confidentialdata for Kingfisher-1 and Sunbird-1).

Fluorescence Alteration of Multiple Macerals: FAMM data was only available forBonaparte-2 (analyses by R. Wilkins, CSIRO). This technique was applied to test problemsassociated with Rv measurements of mixed macerals in the older Carboniferous succession.The data is internally consistent, shows minimal scatter below an equivalent Rv value of 1.2%, and is consistent with other maturity indicators (Rv, TAI and CM). On this basis, theFAMM data in this well is considered a very reliable maturity parameter.

Thermal Alteration Index and Spore Colour Index: TAI and SCI values (based ondiscolouration of organic material) are routinely equated with Rv values, but are somewhatsubjective, and are often expressed on a different scale by different workers. In this study, TMdeterminations by C. Foster (AGSO) and R. Purcell (Consultant) have been converted toequivalent Rv values using an in-house Correlation Chart of Maturation Indices (C. Foster,AGSO, unpubl., March 1996). These data are internally consistent in all wells, but generallyequate to broad ranges of Rv values; thus this parameter is not a sensitive measure ofmaturation level.

TM determinations for Penguin-1 and Petrel-2 (PAU Laboratory, France, in Well CompletionReport) and SCI data for Flat Top-1, Lacrosse-1, Petrel-2 and Tern-1 (Well CompletionReports) have also been converted to Rv values using this in-house correlation chart ofmaturation indices. Using this conversion, the SCI data for Lacrosse-1, Petrel-2 and Tern-1


•411

•••••

••

16 •appear to be consistent with measured Rv data, but the converted SCI data in Flat Top-1 areconsistently lower than measured Rv data. TM data for Penguin-1 and Petrel-2 (PAU, France)are evidently based on a different scale to that used by Foster (unpubl., AGSO, March 1996)and cannot be converted to equivalent Rv values using this chart.

Tmax: Tmax, the temperature at which maximum generation of pyrolysate (S2) occurs, iswidely used as an indicator of maturity, and is commonly plotted against the Hydrogen Index(HI) in a standard Van Krevelan diagram (this diagram purports to identify the generic typeand origin of the organic matter). This parameter might be expected to systematically increasewith depth down a well, however this is seldom the case for the majority of wells studied here.All pyrolysis data were initially screened according to S2 values and PI index (see Edwards &Summons, 1996), and dubious Tmax values due to possible migrated hydrocarbons have beenseparately flagged on the well maturity plots (shown as Tmax(?), Appendix B). Regardless ofthis quality control, Tmax values show considerable variation in most wells, and are thusgenerally of limited value as a maturity indicator. However, in many wells the upper envelopeof the observed Tmax distribution appears to provide a reasonable indication of maturity level(see Maturity Plots for Barnett-2, Berkley-1, Cambridge-1, Kulshill-1 & Tern-1, Appendix B).

Conodont Colour Alteration: Limited CAI data (R. Nicoll, AGSO, unpubl.) is available forfour onshore wells (Bonaparte-1, 2, Keep River-1, Kulshill-1). CM values were converted toequivalent Rv values based on the data presented in Epstein et al. (1977, fig. 11). Althoughthis parameter is semi-qualitative (based on a visual comparison of conodont colour with astandard colour index), it appears to be a reliable measure of maturity in these wells.

Palaeo-Heatflow

The establishment of a palaeo-heatflow curve for each well was an iterative process basedinitially on present-day heatflows, and successive attempts to match observed and predictedmaturity data. It quickly became obvious that elevated palaeo-heatflows were required toachieve a match with observed maturity data, especially for the older Devonian-Carboniferoussection.

A present-day heatflow map for the Petrel Sub-basin is presented as Figure 5. The sub-basinhas a maximum heatflow of 70-74 mW I11-2 in the southern Carlton Sub-basin (Garimala-1and Keep River-1), decreasing to 60-70 mW 111-2 in the northern . Carlton Sub-basin and theSW and NE flank of the offshore portion of the sub-basin, and 50-60 mW 111-2 in the PetrelDeep.

Modelled palaeo-heatflow curves for all wells/pseudo-wells are presented in Figure 6. Amajor Late Devonian heating episode has been modelled during the initial development of thePetrel Rift (tectonic subsidence Phase B), together with superimposed heating pulses forsubsequent major subsidence events identified on the tectonic subsidence plots (Phases D andF). The peak values of the heating episodes were compared to present-day heatflows incomparable tectonic settings (e.g., rifts, post-rift sag basins), and the shape of the heating andsubsequent cool-down curves were modelled from theoretical heatflow curves correspondingto different amounts of crustal extension (see Deighton, 1992; WinBury on-line help plots).Wells within each structural province were assumed to have a similar heatflow history (Fig.6), and modelled heatflow curves were validated against observed maturity data in each well,

^© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

C-T-B High •Lacrosse Tce •Petrel Deep •E Ramp Margin •

-14.5

-15.00

-15.5

Heatf low Map (mW m- 2) @ 0.00 Ma

-11.50

17

and modified as necessary to achieve a best match between observed and modelled maturitytrends.

Initial very high heatflows of 110-140 mW m 2 were modelled during the initiation of thePetrel Rift, and subsequent minor heat pulses (additional 5-10 mW were superimposedon the cool-down curve of that event during subsidence Phases D and F. Although thesepalaeo-heatflows exceed values typical of modern rift settings (70-110 mW m -2, average 80mW r11-2; Allen & Allen, 1990), and active strike-slip basins (80-120 mW m -2 average 100mW ITI-2; ibid.), these high values were required to match observed maturity levels in theDevonian-Carboniferous section. These elevated palaeo-heatflows may indicate formerthermal plumes beneath the Petrel Sub-basin, and much of the extreme total tectonicsubsidence experienced by the sub-basin (up to 7-9 km) may have been controlled bysubsequent thermal decay of these plumes.

Based on the approach outlined above, a reasonable match was achieved between observedand modelled maturity parameters for all wells (see Appendix B).

Figure 5. Present-day heatflow map for the Petrel Sub-basin.


II IIIIII Ill

20

0

KeyC-T-B High^•E Ramp Margin •Carlton SP^•Lacrosse Ice^•CT-Keep Inlet SB •Petrel Deep^•

* R 9 6 0 4 3 0 4 *

TIME (Ma)

CO

350^300 250 200 150

I f'50

IÎÎÎ rJURASSIC TERTIARY

100I^•

CRETACEOUSI^t^1^1^1^1^•^

1^ aÎDEVONIP1^CARBONIFEROUS^1^PERMIAN^11^TRlASSIC

40

Heatf low vs TIME

MODELLED SOURCE ROCK UNITS

Well/Pseudo-well

Barnett-2Berkley-1Billawock-1Bonaparte-1Bonaparte-2Cambridge-1Fishburn-1Flat Top-1Garimala-1Keep River-1Kingfisher-1Kulshill-1Lacrosse-1Lesueur-1Penguin-1Petrel-1APetrel-2Sunbird-1Tern-1Turtle-2AGS0/1-SP3400AGS0/5-SP2800AGS0/7-SP1100CB81-11-SP535HD16-SP400HD16-SP1050

(Y) No effective source rocks

Mid Milligans^Keyling^Hyland Bay

(Y)

(Y)

19

Source Rock Maturation History

Integration of structural, sequence stratigraphic, biostratigraphic and geochemical dataindicates four probable source rock units that underpin three active Petroleum Systems in thePetrel Sub-basin (Colwell & Kennard, 1996; Edwards & Summons, 1996):

• Marine shales and carbonates in the Ningbing reef complex and Bonaparte Formation(Ningbing-Bonaparte Petroleum System)

• Marine shales in the mid Milligans Formation (Milligans Petroleum System)• Coaly shales throughout the Keyling Formation (Keyling-Hyland Bay Petroleum System)• Marine shales within the Hyland Bay Formation (Keyling-Hyland Bay Petroleum System)

The nature and quality of these source units are discussed in detail in Edwards & Summons(1996), and the petroleum systems are described in detail in Colwell & Kennard (1996).

Table 3. Wells/pseudo-wells with modelled source rock units.


20

Although several oil and gas shows have been recorded in the Ningbing Limestone andoverlying Langfield Group (e.g., Garimala-1, Ningbing-1, Keep River-1 and onshore mineralholes), effective source rocks within the Ningbing-Bonaparte Petroleum System have onlybeen intersected in Spirit Hill-1 where they have limited dry gas potential (Edwards &Summons, 1996). Maturation modelling of potential source units within this system have notbeen undertaken since the quality and distribution of potential source units are poorly known,and this system is thought to have only limited hydrocarbon potential.

The mid-Milligans source unit has been modelled in 14 wells/pseudo-wells, the Keylingsource unit in 12 wells/pseudo-wells, and the Hyland Bay source unit in 8 wells/pseudo-wells(Table 3). Effective source rocks were identified on the basis of the following parameters (seefurther discussion in Edwards & Summons, 1996): 1) TOC > 1 %; 2) Hydrogen Index; HI >300 (oil-prone), 150 < HI < 300 (condensate-prone), HI < 150 gas-prone; and 3) Gamma-logvalue greater than about 100-125 API.

Mid-Milligans Source Unit

This source unit comprises marine shales of the Milligans Formation. Sequence stratigraphicanalysis indicates that the most organic-rich intervals penetrated by petroleum explorationwells (as indicated by TOC and HI values) generally occur in the upper portion of the second-order transgressive systems tract of the Milligans Supersequence (Sequences Milligans ASand A6; see Well Folio). This organic-rich interval is characterised by high gamma, low soniclog values, and is about 200-250 m thick. Well and seismic data suggest that this source unitextends throughout the Carlton Sub-basin, Cambridge Trough, Keep Inlet Sub-basin and theMilligans depocentre north of the Turtle-Barnett High (Fig. 7). In the Cambridge Trough, thissource unit represents a condensed transgressive section beneath prominent progradationalhighstand clinoforms that are sourced from the south-southwest.

Rock-Eval pyrolysis data, maceral analyses and palynological evaluation of kerogen (Edwards& Summons, 1996) indicate that shales within the Milligans Supersequence generallycomprise mixed marine and land-derived organic matter and are largely gas-prone. However,samples of immature, oil-prone, marine ?algal-rich shales have been intersected in mineralhole NBF1002, and carbon isotopic and biomarker data suggest that oils recovered at WaggonCreek-1, Turtle-1 and 2 and Barnett-1 and 2 were sourced from similar source rocks (Edwards& Summons, 1996). Maturation modelling of the mid-Milligans source interval is thus basedon kerogen kinetic analysis of the marine ?algal-rich shale in mineral hole NBF1002 (SampleNo. 7925, genetic potential 300 mg/gm TOC). This type of kerogen generates oil and gas overa narrow range of activation energies, generally within the range Rv = 0.7 % to 0.9 % for themodelled wells.

An average TOC of 2 % and effective thickness of 200-250 m was modelled for the mid-Milligans source interval in 14 wells/pseudo-wells (Table 3). Although Barnett-2, Turtle-2,Kulshill-1 and Lacrosse-1 lack effective source rocks within the Milligans Supersequence,they have been included in order to map maturity trends. A modelled age of 336 Ma has beenused for the top of this source unit.

The mid-Milligans source unit first entered the oil and gas maturity zone during the EarlyCarboniferous (Visean), and attained maximum maturity during the Late Permian to Early

O AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

21

Patrol 5Petrel 1A

Tern 1Tarn 4

am 2T m 3

Milligans Supersequence^Major "basin forming" faults *Tem 2 Petroleum exploration well

I^AnticlineNBF-1002

4— Axis of Petrel Deep^•^Mineral exploration hole

Hinge

Figure 7. Distribution of the mid-Milligans source rock unit.

Postulated higher-quality source rocks

<>Gull 1 Petroleum exploration well used in this study

0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

Salt diapir

Precambrian^ basement

Bed Maturity Map (Re/o) : Top Mid Milligans @ 0.00 Mai30.00

,C)

Figure 9. Present-day bed maturity map for the mid-Milligans source unit.

350 300 00.2

50lEMIARV

22

TIME (Ma)250^200^150

• •C •• I

0.5

_0.6

1.3

1.6Key:Barn/Turt-2^•Bon-1,2/Garam-1 •Kingfisher-1^•Keep Rver-1^•Lacrosse-1^•CB81-11a^•Sun/Kulshill-1^•HD16-sp1050^•AGS0/1-sp3400 •HD16-sp400^•

100

20

2.5

3.2

Figure 8. Bed maturity plot for the mid-Milligans source unit in modelled wells/pseudo-wells.

O AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

R 0 %4.0

3.5

3.0

2.5

2.0

1.5

1 0

0.5

••23

Triassic (subsidence Phase F), prior to uplift and erosion during the Fitzroy Movement (Fig.8). It is presently in the oil and gas maturity zone in Bonaparte-1 and 2, Garimala-1,Kingfisher-1, Barnett-2 and Turtle-2, and is overmature in all other modelled wells/pseudo-wells (Figs. 8 & 9).

Hydrocarbon generation plots (Fig. 10A-L) suggest that oil and gas was first expelled from themid-Milligans source unit during the Early Carboniferous (Namurian) from depocentres northof the Turtle-Barnett High (pseudo-wells AGS0/1-sp3400, HD16-sp400, HD16-sp1050), andthat expulsion from the Keep Inlet Sub-basin, Cambridge Trough and deeper parts of theCarlton Sub-basin (e.g., Sunbird-1, Kingfisher-1, CB81-1 1 a, Keep River-1) occurred duringthe Early Permian.

The regional seal for hydrocarbons generated from the mid-Milligans source unit is providedby the Early Permian Treachery Shale, although this seal was locally breached by fault re-

5 activation over the Turtle-Barnett High. The relative timing of hydrocarbon expulsion andemplacement of this regional seal has important consequences for the prospectivity of theMilligans Petroleum System. Figures 11 and 12 indicate that in the depocentres north of theTurtle-Barnett High, the mid Milligans source unit expelled oil and gas during the midCarboniferous prior to deposition of the Treachery seal, whereas equivalent source rocks inthe Cambridge Trough and Keep Inlet Sub-basins expelled oil and gas during the EarlyPermian, immediately after deposition of this regional seal. This contrasting expulsion historyis believed to explain the observed occurrence of composite biodegraded and non-biodegradedoils in Turtle-1 and 2 and Barnett-1 and 2. Jefferies (1988) concluded that these oils formedduring two phases of migration, the first being severely biodegraded prior to migration of thesecond. The present maturation and expulsion models suggest the following scenario:1. Oil expelled during the Early Carboniferous (Namurian) from source kitchens north of the

Turtle-Barnett high was biodegraded as it migrated into shallow Early-Late Carboniferousfluvial/deltaic reservoirs on the Turtle-Barnett High under oxidising conditions.

2. In contrast, oil expelled during the Early Permian from source kitchens south of theTurtle-Barnett High (Cambridge Trough and Keep Inlet Sub-basin) accumulated in nowmore deeply buried Early-Late Carboniferous reservoirs on the Turtle-Barnett High whichwere sealed from oxidising groundwaters by the overlying Treachery Shale.

3. Subsequent fault re-activation across the Turtle-Barnett High (probably during theMiddle-Late Triassic Fitzroy Movement) resulted in partial breach of the Treachery seal,and a second phase of oxidation and biodegradation of the shallower oil accumulations.

In contrast, any hydrocarbon accumulations within more deeply-buried stratigraphic traps tothe north or south of the Turtle-Barnett High would not have suffered biodegradation sincethey were protected from oxidising meteoric groundwaters by intraformational seals. Thusupper slope carbonate mounds identified within the Tanmurra Supersequence north of theTurtle-Barnett High and stratigraphic pinchouts and basin-floor fans identified in the lowerMilligans Supersequence in the Cambridge Trough (see Colwell & Kennard, 1996, chapter 7)are considered prospective oil-charged targets.

Oil shows in the recently drilled Waggon Creek-1 well (see Edwards & Summons, 1996, andColwell & Kennard, 1996, chapter 7) were probably expelled during the Permian from themid-Milligans source unit in the central Carlton Sub-basin. These oils could source onlappingturbiditic sand pinchouts against the basal Milligans Supersequence boundary on the flanks ofthe Carlton Sub-basin, as well as underlying reefal plays in the Ningbing Supersequence.


24


TIME (Ma)360^300^250^200^150^100 50 0

ptrritx-N'^JulttA4se^RE'raeltoh6.0

Irrrto-r'n-trenTirrecr8^'^`1-R(Ass)c ^' frAR

Oil (in situ)^01Oil (expelled)^•Gas (in situ)^•Gat (eXpelled) 0

5.0

• 4.0_ 9-

co

CD

_ 3.0 -2

3

2.0 t,9c ,-

Oil Expelled =^2 bêquiv/m2 1.0Gas Expelled = 8Î equiv/m2TB = 100%

Expulsion On

millnbf :100%0.0

Mid Milligans (6700.0 m.KB, 260.0m. thick) Genetic Potential = 300.00 mg/gm TOO,^100= 2.00%

HYDROCARBON GENERATION PLOT: AGS0/1-SP3400

TIME (Ma)360^300^250^200^150^100 50 0

6.0Î ^.IDE/oi litAABolliFtRobs 11^'îl^"Tiqnss)c 'pfnkAAre^1^JullAsice^RE)AdilEobs 1 1 ENTI)R1r.

Oil (in situ) Oil (expelled)^•Gas (in situ)^•Gas (expelled) 0 5.0

4.0

co

a-CD

3.0

31,3

2.0

Oil Expelled = • I equiv/m2 1.0Gas Expelled =^3 ibl equiv/m2TB = 100%

Expulsion On

millnbf :100%OM

Mid Milligans (6700.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOC, TOO = 2.00%

HYDROCARBON GENERATION PLOT: HD16-SP400

25

Figure 10 A, B. Hydrocarbon generation plots for the mid-Milligans source unit in:A) Pseudo-well AGS0/1-sp3400, and B) Pseudo-well HD16-sp400.

@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

26

I 1 111 1 111 II^1*R 9 6 0 4 3 0 9 *


Oil (in situ)Oil (expelled) •Gas Cal situ) •Gas (expelled) 0

_1.0

0.0

TIME (Ma)360^300^250^200^160

'bEJoi 11 AABolli 'Rots^PtRthhe 11 'TRIASSIC 1 1^JAA4GiC)

100^60^0• ^6.0

herAcItotts

5.0

3.0

3

Oil Expelled = 1 • I equiv/m2Gas Expelled bl equiv/m2TR = 100%

Expulsion On

millnbf : 100%

Mid Milligans (5100.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG = 2,00%


TIME (Ma)260^200^150^100^50^0

1,_,^1^,^.^ _^,^4^

,•

5 . 0R ASS C 1^J A SSIC^I^CRETA EOUS^I^TER I IAR

1 .Y

Oil On situ)Oil (expelled) IIIIGas On situ) inGat (expelled)

millnbf : 100%

Mid Milligans (3050.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG = 2.00%

HYDROCARBON GENERATION PLOT : Sunbird1

350^300E 01 A BO IF RO S

^PER M1A

1.0

0.5

0.0

4.5

4.0

3.5

3 0_ .

2_ 5.

2.0

1 5_ .

27

Figure 10 C, D. Hydrocarbon generation plots for the mid-Milligans source unit in:C) Pseudo-well HD16-sp1050, and D) Sunbird-1.


jill 1, 19 6 Ell, i 1*0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

Oil (in situ) DOil (expelled) •Gas (in situ) IIIGas (expelled)

Oil (in situ) laOil (expelled) I.Gas (in situ) •Gas (expelled) 0

TIME (Ma)350^300^260^200^150^100^50^0

• t^.I^, E 01 A BO IF RO S^P R A^R ASS C 1^J A SIÎ^CRE A EO^ 1SÎÊ i I R^

5.0

4.0

• 3.5 .<0•3

• CD

- Cr-Cr

CD_CI- 2.5

-_2.0

• 0CD

-_1.5

_4.5

Oil Expelled = 18 bbl equiv/mGas Expelled = 14 bbl equivTR varies from 98 to 100%

Expulsion On

millnbf :100%

0.5

0.0Mid Milligans (2300.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOO, TOO = 2.00%

HYDROCARBON GENERATION PLOT : Kingfisherl

TIME (Ma)350^300^250^200^150^100^50^0

Et,P01 A BO IF RO S^P R A^R ASS CI^J A SI^ RO'AC 015SÎ^1 EhTIA RV'

^5.0

-_4.0

-— 0•- 3• co- 3.0—

co• 2.5 -2

- 3• NI

Mid Milligans (2640.0 m.KB, 60.0m. thick) Genetic Potential = 300.00 mg/gm TOO, TOO = 2.00%

HYDROCARBON GENERATION PLOT: Turtle 2

•

- 4.5

Oil Expelled = 0 bbl equiv/m2Gas Expelled = 3 bbl equiv/m2TR varies from 47 to 54%

Expulsion On

millnbf : 100%

29

Figure 10 E, F. Hydrocarbon generation plots for the mid-Milligans source unit in:E) Kingfisher-1, and F) Turtle-2.


I

I I II

I II

II II

* R 9 6 0 4 3 1 3 *


100 50 05.0

millnbf :100% 0.0tz

TIME (Ma)260^200^150300360

• •

Oil (in situ)^DOil (expelled) ElGas (in situ)Gas (expelled) 0

1.0Oil Expelled = 0 bbl equiv/m2Gas Expelled = 2 bbl equiv/m2TR varies from 26 to 31%

Expulsion On

0.5

4.5

4.0

3.5

3.0

_2.5

2.0—

_1.5

Mid Milligans (2400.0 m.KB, 60.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG 2.00%

HYDROCARBON GENERATION PLOT: Barnett 2

350^300

bE1/01 ICAABOtIlFtRAS

Oil (in situ) 0Oil (expelled) miGas On situ) •Gas (expelled) 0

TIME (Ma)260^200^160^100^50

Inti^ta kTrAcAn^• Iîllits•gcleeÎÂ.Inr41.•AlcrsAcÎ•rcrinninl•

3.5 .‹

CD

CD

- 2.5 =

•—•

3

: 10Oil Expelled = 19 bl equiv/mGas Expelled - 1 bbl equivTR = 100%

Expulsion On

millnbf :100%

Mid Milligans (2900.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG = 2.00%

HYDROCARBON GENERATION PLOT : CB81-11a

05.0

4.5

4.0

0.5

0.0

31

Figure 10 G, H. Hydrocarbon generation plots for the mid-Milligans source unit in:G) Barnett-2, and H) Pseudo-well CB-81-11a.


011^1011 II I it*R9604315*@ AUSTRAUAN GEOLOGICAL SURVEY ORGANISATION ^

TIME (Ma)

350^300^250^200^150^100^50^05.0

it)001 ' ABl4I FROUS ta nAncAA‘eÂQC fÎ IÎtbA4C1(?Î .1:10rAdF(16SÎ TATI/111.

]Oil (in situ)^0Oil (expelled) EllGas (in situ) IllGas (expelled) 0

Oil Expelled = 2,Gas ExpelledTA varies from 5

Expulsion On

millnbf :100%

bl equiv/m2bbl equiv/m2100%

Mid Milligans (1500.0 m.KB, 250.0m. thick) Genetic Potential = 300.00 mg/gm TOC, TOG = 2.00%

HYDROCARBON GENERATION PLOT : Keep River 1

TIME (Ma)

350^300^250^200^150^100^50^0,^1^, Â

•1^ 1 ^5.0

E 01 A BO IF RO S^P R A^RASSC I^J ASSICÎ^GRE,TA EOUSÎ^TE I R

Oil (in situ)Oil (expelled)Gas (in situ)^•Gas (expelled) 0

Oil Expelled = 0 bbl equiv/m2Gas Expelled = 5 bbl equiv/m2TA varies from 6 to 45%

Expulsion On

millnbf :100%

Mid Milligans (800.0 m.KB, 250.0m. thick) Genetic Potential = 300,00 mg/gm TOG, TOG = 2.00%

HYDROCARBON GENERATION PLOT : Bonaparte 2

• 4.0

3.5

3.0

_2.5

_2.0

1.5

1.0

0.5

0.0

L4.5

-_4.0

a

1.0

0.5

0.0

33

Figure 10 I, J. Hydrocarbon generation plots for the mid-Milligans source unit in:I) Keep River-1, and K) Bonaparte-2.


1 1

II II 1 1

II I

* R 9 6 0 4 3 1 7*


Oil (in situ)^DOil (expelled)Gas (in situ)^•Gas (expelled) 0

TIME (Ma)360^300^260^200^160^100^50^0

.^L^,^. ^behi ItAABolgiFbots 11^ph4m1Are^"TRIlaselcÎ^Jullasice^6RerAdIEOOS^TERTIARY^

5.0

Oil Expelled = 7 bbl equiv/m2Gas Expelled = 11 bbl equiv/mTR varies from 18 to 83%

Expulsion On

millnbf : 100%

Mid Milligans (1030.0 m.KB, 250.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOO = 2.00%

HYDROCARBON GENERATION PLOT : Bonaparte 1

TIME (Ma)350^300^250^200^150

k^.^1^.^kÎ^.,.

100 50 05.0

bEJoiÂABotliFRots PRÂN'^HIASSICÎ^JURA SI RE A EO S I TE TI R

Oil (in situ)^DOil (expelled)^• _4.5Gas (in situ)^•Gas (expelled) 0

40

3.50

3co

3.0Cr

C1)

_2.5.Ct

3_2.0

NJ

70

co1.5

CD

1.0Oil Expelled =^0 bbl equiv/m2Gas Expelled =^4 bbl equiv/m2TR varies from 6 to 28%

0.5Expulsion On

millnbf :0.0

Mid Milligans (800.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOG,^TOG = 2.00%

HYDROCARBON GENERATION PLOT: Garimala 1

4.5

4.0

3.5

3.0

2.5

2.0

1 5

1.0

_0.5

0.0

cr

3

35

Figure 10 K, L. Hydrocarbon generation plots for the mid-Milligans source unit in:K) Bonaparte-1, and L) Garimala-1.


36

Bed Maturity Map (Ro%) Top Mid Milligans @ 296.00 Ma

Figure 11. Bed maturity map of the mid-Milligans source unit at the time of deposition of theregional Treachery Shale seal (296 Ma).

II^

if^

11* R 9 6 0 4 3 9 *


4

-a3 la

2 g

Time (Ma)350^3006^^DEV I CARBONIFEROUS 11^PERMIAN

Oil (in situ)

III Oil (expelled)

Gas (expelled)

Emplacement ofregional seal

250

—5

16-3/678 0

.0

a,

••

37

Figure 12. Comparative hydrocarbon generation plots for the mid-Milligans source rocks in:A) The depocentre north of the Turtle-Barnett High (pseudo-well site HD16-sp400).B) The Cambridge Trough south of the Turtle-Barnett High (pseudo-well site CB 81-11 a).


38

Keyling Source Unit

Edwards & Summons (1996) identified two source facies within the Keyling Supersequence;marginal marine shales and non-marine coaly shales. The shales have fair source potential,ranging from dry gas-prone Type HUN kerogen to oil and condensate-prone Type WEIkerogen (mean TOC = 2.8 %, mean HI = 95, mean S1 + S2 = 3.6 kg hydrocarbons per tonne).The coaly shales are characterised by Type HRH kerogen and have good oil and gas generativepotential (mean TOC = 35.2 %, mean HI = 230, mean S1 + S 2 = 78 kg hydrocarbons pertonne). Whereas the shales occur throughout the Keyling Supersequence, the higher source-quality coaly shales occur within fluvial and delta plain facies which tend to be concentratedwithin the second-order lowstand and highstand systems tracts in the lower and upper portionsof the supersequence, respectively. However, these coaly sediments only occur as thininterbeds and laminae, and volumetrically probably represent only a few percent of the totalsuccession. Previous source rock sampling strategies do not permit an evaluation of the neteffective thickness of these high source-quality coaly shales.

The Keyling Supersequence is widespread throughout the offshore portion of the Petrel Sub-basin, and organic-rich shales appear to occur throughout its areal distribution (Fig. 13). Coalyshales have been intersected in several wells in inboard, marginal areas (e.g., Barnett-1, FlatTop-1, Kinmore-1, Kulshill-1, Matilda-1 and Turtle-1), but high-quality coaly source rockshave only been identified in Flat Top-1 and Kinmore-1 (Rock-Eval data; Edwards &Summons, 1996). A fairway of possible high-quality source rocks is thus proposed on theeastern flank of the Petrel Deep (Fig. 12), but the basinal continuation of this fairway isunknown (the Keyling Supersequence occurs below TD at Penguin-1 and Petrel-1, 1A and 2).

Maturation models for the Keyling source unit are presented for 12 wells/pseudo-wells (Table3). Modelled TOC values reflect average TOC of shales analysed in each well (ranging from1.5 % TOC in Billawock-1 and Cambridge-1, to 4 % TOC in Flat Top-1) and a net effectivesource thickness of 200-300 m. Maturation modelling of the Keyling source unit is based onkinetic analyses of an organic-rich shale and a coaly shale in Kinmore-1 (AGSO # 8989 and8484, respectively; Appendix C). Both samples have a genetic potential of approximately 300mg/gm TOC, and a similar distribution of activation energies. In the modelled wells, thiskerogen type generates oil within the approximate range Rv = 0.65 to 1.0 %, wet gas at Rv = 1to 1.6 %, and dry gas at Rv > 1.6%.

Due to uncertainties in the net effective thickness of the higher source-quality coaly shales,this source facies has only been modelled in Flat Top-1, pseudo-well site AGS0/5-sp2800(near Kinmore- 1 which was not modelled due to problems associated with salt intrusion),Penguin-1, and Petrel-2. In these wells/pseudo-wells, three scenarios were modelled for mixedshale and coaly shale source rocks; 1) with nil coaly shales, 2) with 10-15 m net effectivethicknesses of coaly shales (representing 5 % of total modelled shale thickness), and 3) with40-60 m net effective thicknesses of coaly shales (representing 20 % of total modelled shalethickness). These three models are equivalent to average net TOC values of about 3-4 %, 5 %and 10 %, respectively, over the total thickness of the Keyling source interval in thesewells/pseudo-wells.

The Keyling source unit is presently at maximum attained maturity level in all modelledwells/pseudo-wells (Fig. 14). Maximum attained maturity levels steadily increased throughoutthe Permian and Early Triassic (subsidence Phase F), increased slightly or remainedessentially constant from the Middle Triassic to Jurassic (subsidence Phases G and H), and


MoyloPlatform

Movieuishill I^ "

utaiIH 2

39

Salt diapir

7 Precambrian basement

Keyling Supersequence

Higher quality coalyshale source rocks

} Major 'basin forming" faults *Tem 2 Petroleum exploration well*$^Anticline^Gull 1 Petroleum exploration well used in this study

—t-- Axis of Petrel Deep^NBF-1002•^Mineral exploration hole

—c— Hinge

Figure 13. Distribution of the Keyling source rock unit.


KeyBill/Lesueur-1 •Cambridge-1 •Flat Top-1 •H016-sp400 •1-3400/5-2800 •Penguin-1 •Fishburn-1 •Tern-1 •Petrel-2 •

R 0%4.0

3.5

3.0

2.5

2.0

1 5

0.5

1.0

0.0

Figure 15. Present-day bed maturity map for the Keyling source unit.


Bed Maturity vs TIME : TOP Keyling

Figure 14. Bed maturity plot for the Keyling source unit in modelled wells/pseudo-wells.

••41•

then increased throughout the Cretaceous (subsidence Phase I) to about present-day maturity• levels. Figures 14 and 15 indicate the following present-day maturity levels for the Keyling

source interval:• • Immature in Billawock-1, Lesueur-1, Cambridge-1, Flat Top-1 and pseudo-well liD16-

sp400.• Oil maturity zone in pseudo-wells AGS0/1-sp3400, AGS0/5-sp2800 (near Kinmore-1)

• and Penguin-1.• Wet gas maturity zone in Fishburn-1 and Tern-1.

• • Dry gas maturity zone in Petrel-2 and pseudo-well AGS0/7-sp1100.

• Wells in the outer and central Petrel Deep (e.g., pseudo-well AGS0/7-sp1100, Petrel-2 and• Tern-1) entered the oil maturity zone during the Permian or Early Triassic (that is, prior to the

Fitzroy Movement structuring events), whereas wells on the flanks of the Petrel Deep (e.g.,• Fishburn- 1, Penguin-1 and pseudo -well sites AGS0/5 -sp2800 and AGS0/1 -sp3400) entered

the oil maturity zone during the Jurassic-Cretaceous (Fig. 14). However, hydrocarbongeneration plots for these well/pseudo-wells (Fig. 16) indicate that the time of peak expulsion

• of hydrocarbons generally occurred substantially later than the time indicated by bed maturity.For example, although the Keyling source interval at Tern-1 first entered the oil maturity zone

4111^during the Early Triassic, peak expulsion of oil probably did not occur until the Cretaceous

O(Fig. 16C), well after the Middle Triassic - Early Jurassic Fitzroy Movement structuring.Similarly, this source unit first entered the oil window at Fishburn-1 during the Jurassic, but

• peak oil expulsion probably occurred in the Tertiary (Fig. 16 D). In pseudo-well site AGS0/1-sp3400, nil hydrocarbons have been expelled from the Keyling source unit.

•Hydrocarbon generation plots for Petrel-2 indicate critical relationships between modelled net

• effective thickness of the Keyling coaly shales, timing of peak hydrocarbon expulsion, and

• time of structuring. If the high-quality coaly shales have a low net effective thickness (netTOC = 3 %), modelled peak expulsion of liquid hydrocarbons occurred during the Late

4111 Triassic synchronous with Fitzroy Movement structuring (Fig. 16B). However, if the high-quality coaly shales have a net effective thickness of 15-60 m (net TOC = 5-10%), then thepeak expulsion of liquid hydrocarbons probably occurred during the Early Triassic prior to the

• main Fitzroy Movement structuring (Fig. 17A, B). Liquid hydrocarbons generated at this timemay have thus migrated to traps on the flanks of the Petrel Deep prior to the formation of the

• Petrel and Tern Anticlines in the Middle-Late Triassic. However, seismic data suggests thatthese structures may have started to grow in the Late Permian (see Colwell & Kennard, 1996,

• chapter 3), and thus they may have been partially charged by hydrocarbons expelled from the

•Keyling coaly shales in the Early Triassic. Regardless of the proportion of high-quality coalyshales, significant amounts of gas were probably expelled both prior to and after structuring.

•At Penguin-1, a low net effective thicknesses of high-quality coaly shales (net TOC = 3 %)

• results in minor expulsion of gas (but no oil) throughout the Cretaceous and Tertiary (Fig.

•16E), whereas a net effective thicknesses of 10-40 m coaly shales (net TOC = 5-10%,) resultsin minor expulsion of oil during the Tertiary in addition to Cretaceous-Tertiary gas expulsion

O history (Fig. 17C, D). At pseudo-well site AGS0/5-sp2800 (near Kinmore-1), gas and oilexpulsion is negligible for all modelled proportions of high-quality coaly shales (Figs. 16F,•

• \ROO

• @ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

42


TIME (Ma)260^200^150^100

N^111 ItTR(ASSC^J I^J11r1A4SIO'^RE'l'AôlEOOS

350^300

bEl./01 ILCAAB411FROI.JS^PtRki

4.0

:

•

10Oil Expelled = 40 bbl equiv/m2Gas Expelled = 146 bbl equiv/m2TR = 100%

Expulsion On

keyling :100%

Keyling (8200.0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG = 3.00%

HYDROCARBON GENERATION PLOT : AGS0/7-SP1100

300350 05.0

50100• e I

L 4.5

: Petrel 2HYDROCARBON GENERATION PLOT

I^•^• • :it^-II

Oil (in situ)^0Oil (expelled) •Gas (in situ)^•Gas (expelled) 0

TIME (Ma)250^200^150

••^• y .

L 4.0

•:10


Expulsion On

keyling : 100%

Keyling (5500.0 m.KB, 300.0m. thick) Genetic Potential - 300.00 mg/gm TOG,

0.5

0.0

.11

50TERTIARY

•

▪ 0.5

• 0.0

05.0

4.5Oil (in situ)^0Oil (expelled)Gas (in situ)^•Gas (expelled) 0

43

Figure 16 A, B. Hydrocarbon generation plots for the Keyling source unit assuming little or no• net effective thicknesses of high-quality coaly shales: A) Pseudo-well AGS0/7-sp1100,

B) Petrel-2.

O AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

II 1 1 I 1 1

II 1 III

III

1

* R 9 6 0 4 3 2 3 *

@ AUS i RALIAN GEOLOGICAL SURVEY ORGANISATION ^

Oil (in situ)^0Oil (expelled)Gas (in situ)ÎnGas (expelled) 0

TIME (Ma)360^300^250^200^150

^100^50

^0

E 01 AABOIJIFROI.IS^PRMIAN) "TRfASSC^1 II^JOIttAS10' I^RE'rA EOOS

Oil (in situ)^13Oil (expelled)Gas (in situ)^MIGas (expelled) 0

-_4.5

-_4.0

5.0


Expulsion On

keyling :100%

Keyling (3900.0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOC, TOC - 3.00%

HYDROCARBON GENERATION PLOT : Tern 1

4.5

4.0

0.5

0.0

Expulsion On

keyling :100%

A..

TIME (Ma)350^300^260^200^150

^100^50

^. A .^p^k•Î^• ,Î ,^ AÂRN'E 01 AABOINIIFtROUS^PtRMIAN^"TRIASSIC^JURASSICÎ^GRETA EOU

05.0

3.5 c)

3co3.0 ,--,

cr

CD

2.5 =

2.0

1.0

;-c- •3

Oil Expelled = 25 bbl equiv/m2Gas Expelled = 28 bbl equiv/m2TFI varies from 69 to 76%

Keyling (3400,0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOC, TOG = 3.00%

HYDROCARBON GENERATION PLOT : Fishburn 1

45

Figure 16 C, D. Hydrocarbon generation plots for the Keyling source unit assuming little or nonet effective thicknesses of high-quality coaly shales: C) Tern-1, D) Fishburn-1.


1 1 1,19 11, II 411111 *0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

•

-_4.5

-_4.0

•

05.0

TIME (Ma)

350^300^250^200^150^

100^

50

- 3.0• co

Expulsion On

keyling :100%...m.—••••==s•—••■

47


Oil (in situ)Oil (expelled) •Gas (in situ)Gas (expelled)

TIME (Ma)350^300^260^200^150^100^50^0

^.. ^1^. 1300i A0180111dROIJS^P R AN^R ASS C I^J A SIC'' 1 ( '^RE4^

5.0A EOOS ' .1 . I EhTaRY' .

E-

• co-_ 3.0 cr

cr

•


Expulsion On

keyling :100%

Keyling (3400.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOC, TOO = 3.00%

HYDROCARBON GENERATION PLOT : Penguin 1

s ris^..sol^••l

Oil (in situ)^1:1Oil (expelled) 1111Gas (in situ)Gas (expelled)

• CU

3.5 •coE-

CD

- 2.5 =•

3. 2.0

• co

Oil Expelled^0 bbl equiv/m2Gas Expelled = 5 bbl equiv/m2TR varies from 3 to 8%

Keyling (2650.0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOO, TOO = 3.50%


- 0 .0•••

4.5

4.0

Figure 16 E, F. Hydrocarbon generation plots for the Keyling source unit assuming little or nonet effective thicknesses of high-quality coaly shales: E) Penguin-1, F) Pseudo-well AGS0/5-sp2800.

1.0

._ 0.5

- 0 .0

111111;111111111111111111O AUSTRATIAN GEOLOGICAL SURVEY ORGANISATION

100 50 07.0

TIME (Ma)350^300^250^200^150

•

Oil (in situ) 13Oil (expelled) •Gas (in situ) •Gas (expelled) 0


Expulsion On

keyling 100%

Keyling (5500.0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOO,

HYDROCARBON GENERATION PLOT

• • 1

6.0

• 5.00

3CD

_4. (I g--.0

7C-

3.0 N.)

L1.0

0.0

: Petrel 2

3

18

16

R ASS C^I^JIJRASSIPE R M1AN RE TAO ECU S TE TI R

: Petrel 2HYDROCARBON GENERATION PLOT

TIME (Ma)350^300^250^200^150^100^50^0

• i^•^•^ 20

14

co-0

10 _•

3

" 8

CsCD

L

4Oil Expelled = 243 bbl equiv/m2Gas Expelled = 181 bbl equiv/m2TR vanes from 98 to 100%

Expulsion On

keyling :190%

Keyling (5500.0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOO,

E 01 A BO IF RO S

Oil (in situ)^0Oil (expelled) IllGas (in situ)^•Gas (expelled) 0

0

49

Figure 17 A, B. Hydrocarbon generation plots for the Keyling source unit in Petrel-2 assumingA) 10-15 m (i.e., 5 % net TOC), and B) 40-60 m (i.e., 10 % net TOC) net effectivethicknesses of high-quality coaly shales.


II^III9I^I^06 () 4 , IJ ( 1.@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

Oil (in situ) DOil (expelled) 111Gas (in situ) •Gas (expelled)

TIME (Ma)350^300^250^200^150

bE1101 AABAlFh01.1S^PhttAlukte^t.TR(ASSIC I I^JORAhle^RE'rA EONI^••

0

TEIRTILIN/

^5.0

4.5

-_4.0

100^50

7_3.5

•-_3.0

-_2.5

-_2.0

•- 1.5

1.0Oil Expelled = 11 bbl equiv/m2Gas Expelled = 15 bbl equiv/m2TR vanes from 30 to 46%

Expulsion On

keyling : 100%



0.5

0.0

Oil Expelled = 52 bbl equiv/m2Gas Expelled = 29 bbl equiv/m2TR vanes from 30 to 46%

Expulsion On

keyling :100%

4.0

CD

1.5

1.0


4.5


0.5

0.0

51

Figure 17 C, D. Hydrocarbon generation plots for the Keyling source unit in Penguin-1assuming C) 10-15 m (i.e., 5 % net TOC), and D) 40-60 m (i.e., 10 % net TOG) net effectivethicknesses of high-quality coaly shales.


1!IR 111 1 1 1111 11 j0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

TI ME (Ma)360^300^250^200^150^100^50^0

kââÂ. A ...,ÎÂâîÂ_Â •5.0E 01 A BO IF RO S^P R Ali.^...TRI

, ASSICÎ I^

JURASSICÎ^GRETA EOUSÎÊitti AR`,

Oil (in situ)Oil (expelled) •Gas (in situ)^•Gas (expelled)

L 4.0

:10Oil Expelled = 0 bbl equiv/m2Gas Expelled = 6 bbl equiv/m2TR varies from 3 to 8% L 0.5Expulsion On

keyling :100% 0.0Keyling (2650.0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOO, TOG = 5.00%


TIME (Ma)350^300^250^200^150^100^50^0

,Â ^.E\01 A BO IF RO S^P R A^R ASS C^J A SIÎ^GRETA FOOS^TATIARY

, ^5.0

Oil (in situ)îjOil (expelled) •Gas (in situ)Gas (expelled) 0

-_ 4.0

2.5

-^3L 2.0

:1.5

:10Oil Expelled = 0 bbl equiv/m2Gas Expelled = 8 bbl equiv/m2

^ •TR vanes from 3 to 8%^ -_ 0.5Expulsion On

keyling :100%^- 0.0



4.5

L 4.5

53

Figure 17 E, F. Hydrocarbon generation plots for the Keyling source unit in pseudo-wellAGS0/5-sp2800 assuming E) 10-15 m (i.e., 5 % net TOC), and F) 40-60 m (i.e., 10 % netTOC) net effective thicknesses of high-quality coaly shales.


I 1^1 0 4 3,1 111 11 11*„,@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

55

Hyland Bay Source Unit

Marine shales and siltstones of the Hyland Bay Formation generally have poor sourcepotential (mean TOC = 2%; mean HI = 55; mean Si + S2 = 1.3 kg hydrocarbons/tonne;Edwards & Summons, 1996). These sediments contain Type IJTJ1V kerogen which is at bestgas-prone.

Sequence stratigraphic analysis of well sections (see Well Folio) indicates that the mostorganic-rich intervals occur within transgressive pro-delta and early highstand delta-slopefacies in the lower portion of the Hyland Bay Member. These source rocks are widespreadthroughout the Petrel Deep (Fig. 18). Higher source quality sediments may occur in the outerportions of Petrel Deep and could have contributed, at least in part, to the gas and condensateaccumulations at the Petrel and Tern Fields. Edwards & Summons (1996) concluded that thecondensate at Petrel-4 has a diagnostically heavy carbon isotopic signature consistent with itbeing generated from mature Permian clay-rich sediments containing mixed land-plant andmarine algal material.

Maturation models of the Hyland Bay source interval are presented for 8 wells/pseudo-wells(Table 3). Modelled TOC values reflect average TOC of shales/siltstones analysed in eachwell (ranging from 1 to 2.5 %), and a net effective source thickness of 250-300 m in outboardwells, decreasing to 50-150 m in inboard wells. Maturation modelling of the Hyland Baysource interval is based on the kinetic analysis of similar kerogen material in the Keylingsource unit, but with a lower genetic potential (HI = 150). In the modelled wells, this kerogentype generates oil within the approximate range Rv = 0.65 - 1.0 %, wet gas at Rv = 1 - 1.6 %,and dry gas at Rv > 1.6%.

The Hyland Bay source unit is presently at maximum attained maturity level in all modelledwells/pseudo-wells (Fig. 19). Figures 19 and 20 indicate the following present-day maturitylevels for the Hyland Bay source interval:

• Immature in Lesueur-1, Flat Top-1 and pseudo-well AGS0/5-sp2800.• Oil maturity zone in Penguin-1, Fishburn-1 and Tern-1.• Wet gas maturity zone in Petrel-2• Dry gas maturity zone pseudo-well AGS0/7-sp1100.

Potential Hyland Bay source rocks in the outer Petrel Deep (AGS0/7-sp1100) first entered theoil maturity zone during the Middle Jurassic, well after Fitzroy Movement structuring. In thecentral Petrel Deep, Petrel-2 first entered the oil maturity zone at the start of the Cretaceous,and the remaining wells in shallow portions of the Petrel Deep first entered this zone duringthe Late Cretaceous-Tertiary.

Hydrocarbon generation plots (Fig. 21) indicate that potential Hyland Bay source rocks in theouter Petrel Deep probably expelled significant quantities of gas during the Tertiary, and to alesser extent, the Cretaceous. In the central Petrel Deep, however, these source rocks probablyexpelled only minor amounts of gas during the Late Cretaceous, and a significant proportionof the original kerogen has yet to been transformed into hydrocarbons (TR = 35-62 %: Fig.21B). In the shallower portions of the Petrel Deep (e.g., Penguin4, Fishburn-1 and Tern-1),maturation modelling suggests that little or no hydrocarbons have been generated or expelledfrom the Hyland Bay source unit.


•56

••

This modelling suggests that the Hyland Bay source unit may have contributed to the gasaccumulations in the Petrel and Tern Fields, but that expulsion of gas from this source wasprobably limited to areas of that source in the outer portion of the Petrel Deep (Fig. 18).

•411

•

•

•••••

@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION. ^ •

57

11/0WA/50

*Tem 2 Petroleum exploration wellSalt diapir Hyland Bay Formation Major "basin forming" faults<>Gull 1 Petroleum exploration well used in this studyNsF-1002•^Mineral exploration hole

Precambrianj basement

Postulated higher-quality source rocks

Anticline

Axis of Petrel Deep

Hinge

Figure 18. Distribution of the Hyland Bay source rock unit.


Key :Lesueur-1^•AGS0/5-sp2800 •Flat Top-1^•Penguin-1^•Fishburn-1^•Tern-1^•Petrel-2^•AGS0/7-sp1100 •

R0°/02.0

1.8

1 4

1.6

12

1.0

0.8

0.6

0.4

0.2

-155127.^127,5'^128^128^129^129^130.00

Figure 20. Present-day bed maturity map for the Hyland Bay source unit.


Bed Maturity vs TIME : TOP Hyland Bay

Figure 19. Bed maturity plot for the Hyland Bay source unit in modelled wells/pseudo-wells.

crcr

3CD

-_3.0

Ill ilIIII

59

Figure 21A, B. Hydrocarbon generation plots for the Hyland Bay source unit in:A) Pseudo-well AGS0/7-sp1100, B) Petrel-2.


* R 9 6 0 4 3 3 5 *

TIME (Ma)350^300^250^200^150^100^50^0.Î^,_

^

115B/ol itasolgiFholis ti^p6ROAN . il ''rdAss)c . 1 I ' 211A4sie^.^REirikA0e1S^5.0

.^1 ER f IARY

Oil (in situ) DOil (expelled) •Gas (in situ) IIGas (expelled)

7_4.0

Oil Expelled = 5 bbl equiv/m2Gas Expelled = 77 bbl equiv/m2TR = 100%

Expulsion On

hyland : 100%

Hyland Bay (5800.0 m.KB, 300.0m. thick) Genetic Potential = 150.00 mg/gm TOC, TOC = 2.00%


TIME (Ma)350^300^260^200^150^100^50^0

, Â ^5.0E 0, A BO IEE 0 S^136110Ale^'"I'FlIASSICÎ^J ASSI

j,^,CÎ^CRETA OUSÎ^TE TI R

Oil (in situ) 121Oil (expelled) 1.1Gas (in situ) •Gas (expelled) 0

-_4.0

c

▪

o

-_2.5

3• 2.0

7J

CD

1.50

-_4.5

Oil Expelled = 0 bbl equiv/m2Gas Expelled = 12 bbl equiv/m2TR vanes from 35 to 62%

Expulsion On

hyland : 100%

Hyland Bay (3700.0 m.KB, 250.0m. thick) Genetic Potential = 150.00 mg/gm TOC, TOG = 2.50%

HYDROCARBON GENERATION PLOT: Petrel 2

•

- 0.57

• 0.0

1.0

0.5

0.0

II I 1* R 9 1 111)1 I !0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

61

Conclusions

Subsidence modelling has identified nine distinct tectonic subsidence phases that controlledthe regional basin-fill architecture and stratigraphic history of the Petrel Sub-basin. A phase ofCambrian-Ordovician subsidence (Phase A) was initiated by crustal extension and extrusionof tholeiitic basalts in the Early Cambrian. The major Petrel rift structure developed in the lateGivetian-Frasnian, and this "syn-rift" extensional phase (Phase B) was terminated bywidespread uplift and erosion in the mid Tournaisian. Subsequent tectonic phases (Phases C,D, E and F) appear to have been controlled by re-newed upper and/or lower crustal extensionand subsequent thermal sag. Many of these extensional-sag cycles were interrupted bysubsequent events, such that the initial rapid mechanical subsidence stage of a new tectoniccycle was superimposed on the slow thermal sag stage of the preceding phase(s).

Compressive tectonism during the Middle Triassic - Early Jurassic (Fitzroy Movement)resulted in widespread uplift and erosion of the flanks of the Petrel Sub-basin, and theformation of inversion anticlines in the central Petrel Deep (Phase G). This compressive basinphase was followed by a phase of minimal net tectonic subsidence throughout most of theJurassic (Phase H). Two subsequent pulses of relative rapid to slow subsidence in the lateOxfordian and Valanginian (jointly Phase 1) correlate with the Argo and Gascoyne spreadingevents along the outer margin of the North West Shelf. A final subsidence phase in theTertiary (Phase J) is poorly constrained in the Petrel Sub-basin.

Maturation modelling of three identified source rock units in the Petrel Sub-basin (midMilligans, Keyling and Hyland Bay source units) has led to a much improved understandingof the maturation, expulsion, migration and trapping history of hydrocarbons discovered in thebasin, and provides new insights into the basin's future exploration potential.

Composite biodegraded and non-biodegraded oils recovered in the Turtle and Barnett wellswere probably charged by hydrocarbons expelled from the mid-Milligans source unit withindepocentres to the north and south of the Turtle-B amett High. Expulsion from the northernsource kitchen probably occurred during the mid Carboniferous (Namurian), and this oil wasbiodegraded as it migrated into shallow, oxidised, fluvial-deltaic reservoirs on the Turtle-Barnett High. Expulsion from the southern source kitchen (Cambridge Trough) probablyoccurred during the Early Permian following the deposition of the Treachery Shale whichforms a regional seal for hydrocarbons sourced from the Milligans Formation. This oilaccumulated in the now more deeply buried stacked reservoirs across the Turtle-Barnett High,and was sealed from oxidising groundwaters by the Treachery Shale. Subsequent faultreactivation, probably during the Fitzroy Movement, resulted in partial breach of this seal, anda second phase of oxidation and biodegradation of the shallower oil accumulations.

Stratigraphic traps within the Cambridge Trough (stratigraphic pinchouts and basin floor fansin the lower Milligans Supersequence) were probably charged by oil expelled from the mid-Milligans source unit during the Early Permian, and these accumulations are unlikely to bebiodegraded since the regional Treachery Shale seal was deposited prior to the expulsion ofoil. Any stratigraphic or combined stratigraphic-structural traps to the north of the Turtle-Barnett High (e.g., upper slope carbonate mounds within the Tanmurra Sequences) wouldhave been sealed by intraformational shales.

@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATIONIMMO

62

Oil shows in the recently drilled Waggon Creek-1 well were probably expelled during thePermian from the mid Milligans source unit in the central Carlton Sub-basin. These oils couldsource onlapping turbiditic sand pinchouts against the basal Milligans Supersequenceboundary on the flanks of the Carlton Sub-basin, as well as underlying reefal plays in theNingbing Supersequence.

The Tern Gas Field and the Petrel Gas-Condensate Field were probably charged by gasexpelled from the Keyling and/or Hyland Bay source units in the outer and central Petrel Deepduring the Late Triassic-Cretaceous (Keyling source) and Tertiary (Hyland Bay source).Shales within the Keyling Supersequence also have the potential to generate minor amounts ofoil; in the outer Petrel Deep, this oil was probably expelled during the Late Permian, prior tostructuring and trap formation in the Middle Triassic - Early Jurassic (Fitzroy Movement). Inthe central Petrel Deep (e.g., Petrel-2), this oil was probably expelled during and shortly afterstructuring, and may have contributed to the condensate recovered at the Petrel Field. On theshallower southern flank of the Petrel Deep (e.g., Tern-1, Fishburn-1), minor amounts of oilwere probably expelled during the Cretaceous and Tertiary.

High-quality, immature to marginally mature, oil-prone, coaly shale source rocks are known tooccur in the Kinmore-1 and Flat Top-1 wells, but maturation models suggest that they haveexpelled little or no hydrocarbons in these wells. If these high-quality source rocks extend todeeper portions of the Petrel Deep (e.g., below TD at Petrel-2), they probably expelledsignificant quantities of oil and gas during the Early Triassic, prior to the main phase ofstructuring and trap formation during the Fitzroy Movement. Thus, any stratigraphic orcombined structural-stratigraphic traps of Permian-Early Triassic age on the flanks of thePetrel Deep may have been charged by oil expelled from the Keyling coaly shale and shalefacies in the Petrel Deep during the Early Triassic.

Acknowledgments

I wish to thank Ian Deighton, Paltech Pty. Ltd., for valuable assistance on all aspects of theWinBury program, and on geohistory analysis in general. AGSO colleagues Jim Colwell andJane Blevin are thanked for input of seismic interpretation data and discussions on structuralaspects of the Petrel Sub-basin, and Dianne Edwards and Chris Boreham for assistance withsource rock and kerogen kinetic data. Ken Baxter (CSIRO, AGCRC) is thanked for discussionson tectonic subsidence patterns and subsidence mechanisms. Heike Struckmeyer, Jim Colwell,Dianne Edwards and Tom Loutit are thanked for their constructive comments and review of thisreport.


•

•

•

•63

• References

• ALLEN, P.A., & ALLEN, J.R., 1990. Basin Analysis, Principals and Applications. BlackwellScientific Publications, Oxford, 451 pp.

•

• BAXTER, K., 1996. Flexural isostatic modelling of the Petrel Sub-basin, Australian North WestShelf. CSIRO Internal Report.

•BICKFORD, G.P., BISHOP, J.H., O'BRlEN, G.W. & HEGGIE, D.T., 1992. Light hydrocarbon

• geochemistry of the Bonaparte Gulf Basin, including the Sahul Syncline, Malita Graben and

•northern Petrel Sub-basin: Rig Seismic Survey 99. Bureau of Mineral Resources, Australia,Record 1992/50.

BISHOP, J.H., O'BRIEN, G.W., BICKFORD, G.P. & HEGGIE, D.T., 1992. Light hydrocarbon• geochemistry of the Bonaparte Gulf Basin, including the Sahul Syncline, Malita Graben and

•southern Petrel Sub-basin: Rig Seismic Survey 100. Bureau of Mineral Resources, Australia,Record 1992/47.

•COLWELL, J.B., BLEVIN, J. B., & WILSON, D.J., 1996. Petrel Sub-basin Study 1995-1996,

• Map and Seismic Folio. Australian Geological Survey Organisation.

• COLWELL, J.B., & KENNARD, J.M, (compilers) 1996. Petrel Sub-basin Study 1995-1996,

• Summary Report. Australian Geological Survey Organisation, Record 1996/40.

• DEIGHTON, I., 1992. Burial and thermal geohistory analysis: A short course. SedimentologistsSpecialist Group, Geological Society of Australia, August 1992, 84 pp.

•

• EDWARDS, D.S., & SUMMONS, R.E., 1996. Petrel Sub-basin Study 1995-1996, OrganicGeochemistry of oils and source rocks. Australian Geological Survey Organisation, Record

• 1996/42.

• EPSTEIN, A.G., EPSTEIN, J.B., & HARRIS, L.D., 1977. Conodont colour alteration - an index

•to organic maturity. United States Geological Survey Professional Paper 995,27 pp.

• ERTHERIDGE, M.A., & O'BRIEN, G.W., 1994. Structural and tectonic evolution of theWestern Australian basins system. The PESA Journal, 22,45-63.

GREENLEE, S.M., & LEHMANN, P.J., 1993. Stratigraphic framework of productive• carbonate buildups. In: Loucks, R.G., & Sarg, J.F. (Eds), Carbonate Sequence Stratigraphy,• Recent Developments and Applications. American Association of Petroleum Geologists Memoir

57,43-62.•

JONES, P.J., NICOLL, R.S., SHERGOLD, J.H., FOSTER, C.B., KENNARD, J.M., &• COLWELL, J.B., 1996. Petrel Sub-basin Stratigraphic Time Chart. Australian Geological• Survey Organisation, Chart 1/96.

• KENNARD, J.M., 1996. Petrel Sub-basin Study 1995-1996, Well Folio. Australian GeologicalSurvey Organisation.

•

^0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION.^•

64

McKENZth, D., 1978. Some remarks on the development of sedimentary basins. Earth &Planetary Sciences Letters, 40, 25-32.

MORY, A.J., 1991. Geology of the offshore Bonaparte Basin, northwestern Australia.Geological Survey of Western Australia, Report 29,47 pp.

MORY, A.J., & BEERE, G.M., 1988. Geology of the onshore Bonaparte and Ord Basins inWestern Australia. Geological Survey of Western Australia, Bulletin 134, 184 pp.


65

Appendix A: WinBury Geohistory Modelling Flow Diagram

1. Subsidence / Uplift Modelling

2. Thermal Modelling3. Source Rock Maturation Modelling

1. Subsidence / Uplift Modelling

A. Single Well ModeStratigraphy:

• Sequences (Mega-, Super-)• Thickness in wells• Sub TD seismic interpretation• Age based on biostratigraphic/sequence chart• Palaeo-water depth (min/max): sedimentology & palaeogeography• Lithology: default porosity/compaction & thermal conductivity

Unconformities / eroded section• Thickness, age of deposition/erosion, lithology

Sea level curve• Exxon Mesozoic converted to AGSO Timescale• ?Palaeozoic

Subsidence/Uplift history• Stripped-basement Tectonic Subsidence• Sediment loading, Compaction, Water depth removed• 'Fine-tune' profile to subsidence/uplift models

Concave extension , convex foreland loadingAdjust water-depth, age; modify unconformities

B. Multiple Well (Basin) Mode• Compare wells from same/adjacent tectonic elements• Ensure consistent subsidence model for each tectonic element

2. Thermal Modelling

A. Single Well ModeSurface & Bottom Hole Temperature:

• OBS & sniffer sea bed temperatures 28 °C all depths• Observed well temperature: Log runs, DST• Estimate stable BHT:

Horner plots: temp & time since circulationMax observed Temperature plus <10 %

Present-day Heatflow: Surface Temp, BHT, ConductivityPalaeo-sea bed temperature for each sequence

• Palaeo-water depth, palaeo-latitude, palaeo-climate


66

Observed maturity data• Rv, FAMM, TAI, SCI, Tmax, CAI, AFTA• Convert each parameter to equivalent Rv level

Palaeo-Heat Flow:• Tectonic events/processes (Extension & Thermal Sag)• Iterative to match Modelled & Observed maturity• Modify subsidence/unconformity models as necessary:

- Thickness, Age, Lithology of eroded section

B. Multiple Well (Basin) Mode

• Present-day Heat Flow Model• Palaeo-Heat Flow Model for each tectonic element

Re-evaluate & re-iterate everything to achieve best model !!

3. Source Rock Maturation Modelling

Define Source Unit in Each Well and Pseudo-Well Source Kitchen• Depth to top of source unit• Thickness of source unit• Average TOC of source unit• Type of kerogen(s)

Define Distribution of Source Unit• Create well file for wells/pseudo-wells with source unit

Define Age of Source Unit• Create source unit File and define age of top of source unit

Hydrocarbon Generation Plots: Select View Type• Summary:^Time (well total)^bbl equiv./m2

Time (all layers)^bbl equiv./m2Depth & Calibration bbl equiv./m2

• Layer^Volume^bbl equiv./m2Rate^bbl equiv./m2

• Sub-layer^Cumulative Volume bbl equiv./m3Cumulative HC^HC generated mg/g TOCRate Volume^bbl equiv./m3: Rate/MaRate HC^HC generated mg/g TOC: Rate/Ma

Bed Maturity Plots• Generate for well/pseudo-well source unit file

Bed Maturity Maps• Generate for present day maturity (Ma =0)• Generate for times of critical importance (time of structuring, seal emplacement etc.)


•••

••••

67

Appendix B:

• Basin Stratigraphy Parameters

• Observed versus Computed Maturity, Heatflow and Tectonic Subsidence,• Geohistory & Hydrocarbon Generation Plots for each well and pseudo-well

(alphabetical order)••

•••••

BASIN STRATIGRAPHY PARAMETERS

Sequence Age Age Min^Max Seabed PalaeoTop Base Water Depth Temp. Lat.(Ma.) (Ma.) (m) (m) ( °C) ( ° S/N)

Tertiary 000.0 060.0 -20 30 27.0 14Hiatus/Erosion 5 060.0 065.0 20 200 25.0 35Bathurst Island 065.0 136.0 20 200 25.0 40Flamingo 138.0 152.0 10 50 21.0 50Plover 154.0 195.0 -20 20 20.0 45Hiatus/Erosion 4 195.0 200.0 -20 10 16.0 40Malita 200.0 220.0 -20 10 16.0 35Fitzroy Erosion 220.0 230.0 -20 20 14.0 30Hiatus 3 230..0 238.0 -20 20 12.5 30Cape Londonderry 238.0 245.0 -20 20 11.0 35H4 + Mt Goodwin 245.0 257.0 10 50 9.0 35Hyland Bay 257.0 270.0 10 50 7.0 40-45Fossil Head 272.0 291.0 30 100 5.0 50Keyling 291.0 294.5 -20 30 5.0 50Treachery 294.5 296.0 -10 30 5.0 45Kuriyippi 296.0 314.0 -20 30 5.0 40Point Spring 315.0 324.0 10 60 12.0 40Tanmurra 2 324.0 327.0 20 100 18.0 15Tanmurra 1 327.0 328.0 20 100 19.5 15Erosion 2 328.0 330.0 20 100 20.0 15Milligans A5-8 330.0 337.0 30 100 21.0 15Milligans A1-4 337.0 345.0 30 100 23.0 10Milligans praecipua 345.0 347.0 10 30 24.0 10Langfield 347.0 354.0 10 60 24.5 5Ningbing 354.0 361.0 10 60 25.0 5Erosion/Hiatus 1 361.0 363.0 10 60 25.0 5Cockatoo 363.0 369.0 -10 60 25.0 5?Devonian Salt 369.0 375.0 -10 20 25.0 5


68

•••

DE CARBONIFEROUS PERMIAN TRIASSIC CRETACEOUS^TERTIARY

Tanmurra.,nru-s,0„51,Q,04

Milligans praecipua

--"JMnitata^ru

Sea Level^—Sediment Interface •ISO-Ro

TertiaryJVVVVVVVVVL.

Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

Tanmurra 2

?Ningbing

?Cockatoo

GEOHISTORY PLOT: Barnett 2

20 -.

0 -

Heat FlowTectonic Subsidence -11-(Min/Max Range)^4-

Present Heatfiow 55.243 (mw m-)

TIME (Ma)350^300^250^200^150

1^,Î^,Î^,^.Î^.^1 100 50

0.0

160

140

120

z_:-- 80

0 -

40-0E1^CARBONIFEROUSÎ PERMIAN I TRIASSIC

_ 0.5

_ 1.0rs)

1.5 rn

2.0

I JURASSIC CRETACEOUS TERTIARY 2.5

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Barnett 2


••••

••••••

0.2^ 0.5VR (LOG SCALE)

0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5 3.2^4.01 1 I^1111111

-0.5Oil and Key :

Gas VR^•TAI Foster tTmax

-0.0 Tmax(?)^XTertiary

fvVvvVVVVVLHyland Bay

0.5Fossil Head

Keyling 1.

V)Treachery

1.5 .Kuryippi

Point Spring 0_c'

•1Tanmurra 2 20

Tanmurra 1furvvafscsapArk.

Top Oil andiGas Maturity ZoneX^+

iui m.

Milligans praecipua 2.5

jvv.4 artqa2trA"-

ase •I an.âsâuriy one 0

?Ningbing3.0 7

?Cockatoo- Maturity Method : Kinetic

OBSERVED vs COMPUTED MATURITY PLOT: Barnett 2

TIME (Ma)350^300^250^200

Strat^Source RocksÎ^ I/^•ÎÎÎ

150II

100 50^06.0

0.0 DE' CARBONIFEROUS [PERMIAN' TRIASSIC' JURASSIC (CRETACEOUS1 TERTIARYÎ

TertiaryOil (in situ)ÎM

AfWVV Oil (expelled)^•Hyland Bay Gas (in situ)^la

Gas (expelled) 1:1 5.0_0.5

Fossil Head

1.0 Keyling 4 0 -BCDcr

Treachery

••=z 1.5 •3 0_CD

=Kuryippi

rs.3Point Spring • •

I-- 2.0 Tanmurra 2 _ 2.0-,

Tanmurra 1C

M. MIlliame

2.5 Milliganspraecipua 1 0

-"kneltr

?Ningbing3.0

?Cockatoo _ 0.0Mid Milltgans: Oil Expelled =^0, Gas Expelled = 2 Pt,' equiv/m2

HYDROCARBON GENERATION PLOT: Barnett 2

69


70

0-0.5

0.0

1.5

Maturity Method : Kinetic

Sea Level^—Sediment Interface 15ISO-Ro 2.0

Fossil Head

Keyling

Treachery

GEOHISTORY PLOT: Berkley 1

50100I^.^•

0 -

=7: 60

40-

pEl CRETACEOUS TERTIARY^ts-_ 2.5CARBONIFEROUS^I PERMIAN I TRIASSIC I^JURASSIC

Heat RowTectonic Subsidence .11-(Min/Max Range)^+

0 —Present lieatflow = 66.876 (mi/V^3.0

TIME (Ma)350^300^250^200^150

•^L. • _ •^•^.^.^1^1^1

^-0'41

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Berkley 1

120 -

100

0.0

0.5

20


1.6 2.0 2.5 3.2 4.0

Tertiary,MA.AftMnAIVV

800Maturity Method : Kinetic

0.2^0.5 0.6 0.7 0.8VR (LOG SCALE)

1.0^1.3

Fossil Head

Keyling

Treachery

OBSERVED vs COMPUTED MATURITY PLOT: Berkley 1

71


72

TIME (Ma)350^300^250^200^150 100^50I^ 1ÎII

PDEI CARBONIFEROUS I PERMIAN I TRIASSIC I(

^

JURASSICÎ •t_r I ■

CRETACEOUS I^TERTIARY

0.5

0.60.70.8

1 01.31.6

.k1/4\0 1711111111111111111111111111112.0

2.50^ iso

3.2

Sea Level^—Sediment Interface BISO-Ro

Milligans A1-4

LangfieId

Ningbing

Cockatoo

Pc.rd SOnn9

Tanmurra 2./VA/WV

Milligans A5-8

GEOHISTORY PLOT: Bonaparte 1

Heat FlowTectonic Subsidence IF(Mm/Max Range)^1-

100 50•

2.5TERTIARYCRETACEOUS

40

20

350^300„

TIME (Ma)250^200^150

0.0

160

_0.5

CARBONIFEROUSÎ PERMIAN I TRIASSIC I^JURASSIC

Present Heatfiow = 60.129 (rrivy m-P.) 3.0

120

100

80

60

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Bonaparte 1


73

02VR (LOG SCALE)

0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0IÎÎÎ

vcroNrcargcrotroPoint Spring

Tanmurra 2

+ +0.5

.n.rv‘knn*vvy

Milligans A5-8

Milligans A1-4

Langfield

Ningbing

Cockatoo

-0.5

0.0

•^V w•^V.11•VVV•VV••VV,•“••

Top Oil and Gas Maturity Zone © 753 m.

3.0

3.5 --- Maturity Method : Kinetic

KeyTAI Foster tTmaxCAITmax (9) X

Oil andGas

OBSERVED vs COMPUTED MATURITY PLOT: Bonaparte 1

XX

2.0.

TIME (Ma)200^150 050100250300350

Strat.^Source Rockskvfp14

1[21111Ît^ I^.11Îj.11111L 1 1. 111 ,

DEI CARBONIFEROUS IPERMIANITRIASSIC I^JURASSIC^CRETACEOUS I TERTIARY I

0.0Tanmurra 2

„ruirs1ritRoinn

Point Spring

Milligans A5-8

Mid Milligans

Milligans A1-4

Langfield

Ningbing

3.0Cockatoo

1.0

Mid Milligans: Oil Expelled = 7, Gas Expelled = 11 bbl equiv/m23.5

0.5

Oil (in situ)Oil (expelled)Gas (in situ) EGas (expelled) 1:1

HYDROCARBON GENERATION PLOT: Bonaparte 1

_6.0

5.0

_4.0

1.0

0.0

0

3CD


TIME (Ma)

350^300^250^200^150I^ •

1)81 ICAAB6N)E1401.1)S 1=,ERMIAN I TRIASSIC r^JURASSIC^f CRETACEOUS^TERTIARY

100^50

crketekrr,,,,swtgrtrePte0

Tanmutra 2„nivvvtructnAfu

Milligans A5-8

Mifligans A1-4

Langfteld

Ningbing

Cockatoo


Sea Level^—Sediment Interface 111ISO-Ro

GEOHISTORY PLOT: Bonaparte 2

TIME (Ma)

350^3001Î

250, •^,^•^• .

200 150 100 50IÎ^.1^, 0.0

160

140

120 1.0 1-7

1001.5 c'" 1

80 -0

360

40• CARBONIFEROUS I PERMIAN 1^TRIASSIC I JURASSIC CRETACEOUS TERTIARYÎC. 2.5

20 ^

--.

=

Present Heatflow 64.579 (miN m-g) 3.0

Heat FlowTectonic Subsidence fli•(Min/Max Range)^+

0HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Bonaparte 2

74

^0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

75

Oil andGas

Milligans A5-8

0.0"fofteVercrotft.

sulekkOVViivvto

VR (LOG SCALE)0.2^0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

I

1.0

Milligans A1-4

Langfield

Ningbing

2.5

Cockatoo3.0

-0.5

0.5

Point Spring

Tanmurra 2

OBSERVED vs COMPUTED MATURITY PLOT: Bonaparte 2

TIME (Ma)200^150250 100 50300 0

Strat."'""'KUnVit.h31"

,nnkniOriAnn

0.0

350Source Rocks TI^ Ltt

I11.111.)

DEI CARBONIFEROUS IPERMIANITRIASSICI^JURASSIC^CRETACEOUS I TERTIARY

0.5Milligans A5-8

Mid Milfigans

Milligans A1-4

Langfield

Ningbing

2.5

Cockatoo

3.0Mid Milligans: Oil Expelled = 0, Gas Expelled = 5 bbl equiv/m2

Point Spring

Tanmurra 2Oil (in situ) InOil (expelled) •Gas (in situ) ElGas (expelled) 13

HYDROCARBON GENERATION PLOT: Bonaparte 2

_ 6.0

_ 5.0

1 0

_ 0.0


100 50TIME (Ma)

350^

300^

250^

200^150DE CARBONIFEROUS PERMIAN TRIASSIC^JURASSIC^CRETACEOUS^TERTIARY

0-0.5

0.011111.1111111M.MMME

Tenr0Ary

Hyland Bay

0.5

1.

1.62.0

2.5Maturity Method : Kinetic

Sea Level^—Sediment Interface aISO-Ro

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

77760"046.70.01

Bonaparte

Basement

GEOHISTORY PLOT: Cambridge 1

TIME (Ma)350^300^250^200^150

^100^50^0

..tii ^ ,^ 0.0

F

160:

140

120 .,

100

807,

0.5

1.0

1 5 c3-^c

:2.0 rn

--0

_2.5= 60

_3.040 -.

El^CARBONIFEROUS^I PERMIAN I^TRIASSIC I JURASSIC CRETACEOUS^TERTIARY 3.520 .

Heat FlowTectonic Subsidence II(Min/Max Range)

Present Heatflow = 56,410 (rriW th-R) 4.0

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Cambridge 1

7 6


VR (LOG SCALE)0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0I

0.2

-0.5Key :

Dry Gas VR •TAI Foster #Tmax +Tmax (?) X

erv,Ar,

Hyland Bay

0.0

2.0Top Dry Gas Maturity Zone ril) 2049 m.


Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

TantnUfra 2

f=1

Bonaparte

Basement

77

OBSERVED vs COMPUTED MATURITY PLOT : Cambridge 1


78

100 50TIME (Ma)200^150 0

-0.5

2.5Maturity Method : Kinetic

Sea Level^—Sediment Interface ISISO-Ro

GEOHISTORY PLOT: Flat Top 1

3.0

250300350

Tertiary.$1.11.W.MOVVNJ

Bathurst Island

Plover

taifetMtry

H4 + Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

Kuriyippi

0.5

2.0

0.0

1.0 11)

C./1

r.r)1.5 C-1

TERTIARYCRETACEOUSE^CARBONIFEROUS^I PERMIAN I TRIASSIC I^JURASSIC

Heat FlowTectonic Subsidence •(Min/Max Range)^+

Present Heatfiow 67.947 (mils, m-2)1 2.0

1 1.8

TIME (Ma)350^300^250^200^150^100^50^0

•^ ./11 •II^• ,^0.0...

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Flat Top 1

160:

140:

120

F..-- 80:

= 60

407

20:

0 —

11.6

1 0.2

1 0.4

0.6


VA (LOG SCALE)0.2^ 0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

-0.5

TertiaryIVVVVVVVVVU

Bathurst Island

V)Plover

AIVIRCIARRAft1Cape Londonderry

1.5

H4 + Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

Kuriyippi

OBSERVED vs COMPUTED MATURITY PLOT: Flat Top 1

TIME (Ma)350^300^250^200^150^100^50

Strat.^Source Rocks^litti.^ 11111,12j.2.1.I11_11.■11/,1

0_6.0

0.0 ill CARBONIFEROUS '1'PERMIAN' TRIASSICIJURASSIC^( CRETACEOUS^TERTIARY^I

Tertiary Oil (in situ)^Cip."VVVVVVVN, Oil (expelled)

Gas (in situ)^ifflGas (expelled) 0 _5.0

Bathurst Island

0.5

4 0 2-FInnim,10 Cs

Plover Cr

C1)

1.o --INAIMNAALondonderry

3.0 =.Hyland Bay: Oil Expelled =^0, Gas Expelled =^0 bbl equiv/m2

3H4 + MtGoodwin

••

Hyland Bay _2.0Hyland Bay

Fossil Head •1 5

Keyling Keyling1 .0

Treachery

2.0 Kuriyippi _ 0.0Keying: Oil Expelled =^0, Gas Expelled =^0 bbl equiv/m2

HYDROCARBON GENERATION PLOT: Flat Top 1

V)

79


80

TIME (Ma)350^300^250^200^150 100^50

40

20

pÎtI^1Î^1ÎIÎ^ I,.^•Î. ÎÎ,,IÎL •1^2

DE1 CARBONIFEROUS 1 PERMIAN I TRIASS IC I^JURASSIC^1 CRETACEOUS 1^TERTIARY

7cm777777,1imv°

Milligans A5-8

Milligans A1-4

rt.ihnow.n.nrykrLangfield

Ningbing

Cockatoo


GEOHISTORY PLOT: Garimala 1

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Garimala 1

CARBONIFEROUS^1 PERMIAN 1 TRIASSIC 1^JURASSIC

Heat FlowTectonic Subsidence 4(Min/Max Range)^+

CRETACEOUS


VR (LOG SCALE)0.2^ 0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

3.5 Maturity Method : Kinetic

NO2.5

3.0

-0.5Oil and

Gas

7477gPtT4Cirn7747Tanmurre 2

I'VVVVV`VNA.firk,

Milligans A5-8

Top Oil and Gas Maturity Zone @ 732 m.

Milligans A1-4

INAAAINAAJVV1.1Langfield

0.0

0.5

Ningbing

Cockatoo

OBSERVED vs COMPUTED MATURITY PLOT: Garimala 1

TIME (Ma)350^300^250^200^150 100 50^0

Strat.^Source RocksÎ^ IÎ I I _6.00.0

-"MACVrthtf' DB CARBONIFEROUS IPERMIA^TRIASSIC!^JURASSIC CRETACEOUS I TERTIARYTanmurra 2

Oil (in situ)^laOil (expelled)ÎIIGas (in situ)^la

0.5 Milligans A5-8

Gas (expelled)0_5.0

Mid Milligans

1.0 4 0 51

1.5 Milligans A1-4

4.1C..r) 3.0 =

1

3Cl") 2.0

VWJALangfield

14JC=1:1 _ 2.0

_2.5 Ningbing

1.03.0

Cockatoo

.A4-4••••■•••■■•••••Mid Milligans: Oil Expelled =^0, Gas Expelled =^4 bbl equiv/m2

3.5 0.0

HYDROCARBON GENERATION PLOT: Garimala 1

81


82

100 50 00.0•

TIME (Ma)350^300^250^200^150

I^•ÎÎ^1

_ 3.0Present Heatflow 72.190 (mW th-2)

0.0

1.0

2.0

rri-10

3.0 v)co(/)

4.0 ---B

5.0

6.0

"OVVVVVVVV1.

Langfield


Sea Level^—Sediment Interface 8ISO-Ro 7.0

Kuryippi

Tanmurra 2

Milligans A 5-9

Milligans A1-4

Ningbing

Cockatoo

GEOHISTORY PLOT: Keep River 1

160

0.5_140

120 1.0_M-1fC/

100

1.5

80 1-7--r-

60 2.0

40CAR NIFEROUS PERMIANÎ TRI SIC I JURASSIC CRETACEOUS TERTIARY 2.5

20 ^

^

Heat FlowTectonic Subsidence 11-(Min/Max Range)^+

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Keep River 1


83

0.2VA (LOG SCALE)

0.5 0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5^3.2 4.0IÎÎÎ^liftÎI

100 50 0

1.0

0.0

2.5 7X 4"-- •

-0.5

Key :VA^•TAI Foster^tTmaxVP RobertsonCAI^VTmax (?)^X

Oil andGas

0.5 7

X

1 .0 Top Oil and Gas Maturity Zon•@ 964 m.

X +

3.0 7X

X

3.5 .Maturity Method : Kinetic

•^

0.0 -

OBSERVED vs COMPUTED MATURITY PLOT: Keep River 1

TIME (Ma)200^150250300350

Strat.^Source RocksTreacly,

Kulyippi

Tanmurra 2"vvvvv-kruN.

Milligans A 5-9

CE CARBONIFEROUSIPERMIANITRIASSIC I

Oil (in situ)Oil (expelled) •Gas (in situ) MIGas (expelled) 0

IIIII^••Î

JURASSIC^CRETACEOUS '1 TERTIARY_ 6.0

5.0

MIU Milligans

4.0

5.0

Milligans A1-4

AINSW./UNA

Langfield

Ningbing

Cockatoo

4 0 2-CD

••

Mid Milligans: Oil Expelled .--- 22, Gas Expelled^18 bbl equiv/m2

HYDROCARBON GENERATION PLOT: Keep River 1

00

1.0


84

Sea Level^—Sediment Interface WISO-Ro

GEOH1STORY PLOT: Kulshill 1

JNIVVVVVVVVV

Milligans A5-8

Milligans A1-4

PLAJW.A.MAIVNingbing

"raggelY"

Keyling

Treachery

Kuryippi

Point Spring

Tanmurra 2

Cockatoo


_3.0Present Heatflow = 64.217 (mW m-%)

TIME (Ma)350^300^250^200^150

0.0

140

E11^CARBONIFEROUS^I PERMIAN^TRIASSIC I^JURASSIC

Heat FlowTectonic Subsidence -IF(Min/Max Range)^+

40

20

0HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Kulshill 1


VA (LOG SCALE)

0.2^

0.5 0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5^3.2 4.011^11111111

-0.5 -

0.0

0.5

to^ + + ^

1 .5 7 Top Oil and Gzis Maturity Zone G 1117m.

Base Oil and Gas Maturity Zone @ 1826 m.

pl3 2.0 -=Cl)

1-^-a. 2.5 -L.L.1

3.0 --

3.5

4.0 7: Maturity Method : Kinetic

'r

X

x x

Oil andGas Key :

VR •Tmax +CAI VTmax (/Z)

OBSERVED vs COMPUTED MATURITY PLOT: Kulshill 1

ri.rvvvw.n.n.n.AFossil Head

Keyling

Treachery

Kuryippi

Point Spring

Tanmurra 27VVVOVVVVVU

Milligans A5-8

Milligans A1-4

n.Aft.n.A.AAA.Ningbing

Cockatoo

85

^@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

86

350^300^250151 CARBONIFEROUS PERMIAN

TIME (Ma)200^150

0.0

1.0

4.0


Sea Level^—Sediment InterfaceISO-Ro

5.0

100^50

NTfiS'AZI-Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

Tanmurra 2

Tanmurra 1

Intra-Synrift 2

Intra-Synrift 1

GEOHISTORY PLOT: Lacrosse 1

TIME (Ma)200^150 100^50350

El^CARBONIFEROUS^I PERMIAN I TRIASSIC I^JURASSIC

Heat FlowTectonic Subsidence -1M-(Min/Max Range)

CRETACEOUS

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Lacrosse 1


87

VR (LOG SCALE)

02^ 0.5^0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5 3.2^4.01^1 I^1 I I I I I^I

-0.5Oil and

Key :GasVR^•TAI Foster

Ternary^vvH4+ Mt Goodwin

0.0 .^„ TmaxVR ?inertini•I501 (VR Ergv

Hyland Bay0.5 7

Fossil Head

1 .07Keyling

+Treachery 1 .5 7

Kuryippi -= 2.0 -v)

Top Oil and Gas Maturity Zone @ 22551.

Point Spring-

LJ-1CZ 2.5 -

Tanmurra 2

3.0 7 Base Oil and Gas Maturity Zone @ 2970 m.

Tanmurra 1

jvlivlfirkr,1{:~rvinainanainanag

3.5 7

Intra-Synrift 2

Intra-Synrift 1 4.0 - Maturity Method : Kinetic

OBSERVED vs COMPUTED MATURITY PLOT: Lacrosse 1


88

Synrift Fan-Delta 3SynnIt fon-Oelta

Synrift Fan-Delta 1

TIME (Ma)350^300^250^200^150^100^50

•^ I toEl WoOmPdtotis . 1 PERMIAN I TRIASSIC 1 I JURASSIC 1^( CRETACEOUS 1^TERTIARY

0.0


Sea Level^—Sediment Interface •ISO-Bo

GEOHISTORY PLOT: Lesueur 1

1.0

nnrirtrtnnrfreno

jgal-likFri‘e0Y6011:14

,ov.vmmv.:NeArvu4.0

5.0

Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

Tanmurra ?1+2

100 500.0


_ 3.0Present Heatfiow = 55.529 (mW m-)

TIME (Ma)

350^300^250^200^150

?El^CARBONIFEROUS^1 PERMIAN 1 TRIASSIC 1^JURASSIC

20

Heal Flow^4111,Tectonic Subsidence -••(Min/Max Range)^+

100-

80-

60

40

-

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Lesueur 1

_ 0.5

120


Synrift Fan-Delta 3Syn. Fen-De. 2

Synrift Fan-Delta 1

VR (LOG SCALE)0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0I

0.2

-0.5

134:1414P444:43434„, „„. A amokWifOrTosOdwirr

-,v‘rgtOXIONV,-fk-

0.5

1.0 7

3.5 7


Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

Tanmurra ?1+2

OBSERVED vs COMPUTED MATURITY PLOT: Lesueur 1

TIME (Ma)350^300^250^200^150^100

Strat.^Source Rocks^ 11111101,14Î1^ )

50 0_ 6.0

0.02'416111109".01111a..

DEI CARBONIFEROUSLIPERMIANITRI ASSICI JURASSIC^CRETACEOUS I TERTIARYÎ

:(1‘1121'144.o

;■;;,:V advIllfkrkn Oil (in situ)^cmOil (expelled)^•

0.5 Hyland Bay Gas (in situ)îsGas (expelled) 0 _5.0

Fossil Head

1.0Keyling

Keyling 4 0 Q1.5 CD

Treachery

CD2.0 _ 3.0 sHyland Bay: Oil Expelled =^0, Gas Expelled =^0 bbl equiv/m2

col Kuryippi

3

o_L.LJC='

2.5

3.0

• •

- 2.0 --Point Spring

Tanmurra?1+2

3.5-"WO**. Cv".

Synnfl F.-Delte 3

4.0 Syn,,, Fan-Denn 2

SynriftFan-Delta 1

Keyling: Oil Expelled =^0, Gas Expelled =^0 bbl equiv/m2

HYDROCARBON GENERATION PLOT: Lesueur 1

89


ApsierstystAdvIT y-^xvtawlafACY‘fuH4 + Mt Goodwin

Hyland Bay

Fossil Head

KeylingTreachery

Kuriyippi

Point Spring

Tanmurra

Synrift

TIME (Ma)350^300^250^200^150^100^50

att.dazom,sintal.,

0.5O.

1.01.31.62.02.53.2

4.0

tk\



GEOHISTORY PLOT: Penguin 1

,^0.0

TIME (Ma)200^150 100 50350 300 250

I

0.5

to100

80 -

60

40

20FN.I^CARRONIFFRO S^I PERMIAN-1 Heat Flow *Tectonic Subsidence li.(Min/Max Range) ÷

0 —

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Penguin 1

90


91

Keyling: Oil Expelled = 0, Gas Expelled = 10 bbl equiv/m2

HYDROCARBON GENERATION PLOT: Penguin 1

VA (LOG SCALE)0.5 0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5^3.2 4.0

IÎ IIÎ^t0.2

-0.5

Tertiary

Ann.rwtrtAnniu

MalitaxvvNA.A.A.rtfkrueu

Cape Londonderry

C_LaJ

H4 + Mt Goodwin

Hyland Bay

Fossil I-lead


3.0 -OBSERVED vs COMPUTED MATURITY PLOT : Penguin 1

Dry Gas

Top Oil Maturity Zone at 2149 m.

4" X +

Bathurst Island

FlarrnndO

Plover

TIME (Ma)

Strat.^Source Rocks350^300^250^200^150

IÎIÎÎÎ^ IÎI^•Î^/Î

IPERMIANI TRIASSIC I^JURASSIC

100)ÎIÎÎ

50I _ 6.0

0jgatir?r'srrAal7s

DEI CARBONIFEROUS I CRETACEOUS I TERTIARY

nMower Oil (in situ)Êa

Oil (expelled)^•Gas (in situ)Êl

Hd .M1 ClowAnn Gas (expelled) 0 5.0_2 Hyland Bay

Fossil Head

Keyling

4 4.0 9-Treachery

CD

Kuriyippi

-=Lr>

6Point Spring _3.0 =_ .Hyland Bay: Oil Expelled =^0, Gas Expelled =^0 bbl equiv/m2

CO 3V) • •

8 Tanmurra 2 0_^•70

.S.-)CD

10

Synrift

12


92

TIME (Ma)200^150350 300 250 100 50

JVVVV1.11A.A.11.11.0Bathurst Island

Flamingoivvv,:artn.A.n

Cape Lontlondanv

H4 Mt GoodwinWk. Bev

Fossil Head

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

Synrift

GEOHISTORY PLOT: Petrel 1A

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Petrel 1A

250TIME (Ma)

200 150 100^50.^„^,Î

00.0

1.0

2.0

3.0

4.0

-13

5.09

6.0

7.0

PERMIAN I^TRIASSIC JURASSIC I CRETAC oi* SÎ^• =.

Present Heatfiow = 55.167 (mW m- 2) 8.0

350^300.Î^.^.^.

120

100

80 -^

40 -

20

Heat Flow^*STectonic Subsidence •11-

I

(Min/Max Range)^+

0


•

VR (LOG SCALE)0.5 0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5^3.2 4.0

I^I^H^1^ I^II^10.2

.1VtlVVVIVVVVVIBathurst Island

Flamingo

juv‘rjotn.nivt,

Top Dry Gas Maturity Zone 0 4636 m.


Cap, London:bevy

114 + Mt GoodwinHyland Boy

Fossil Head

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

Synrift

OBSERVED vs COMPUTED MATURITY PLOT: Petrel 1A

93


94

Bathurst Islandn4nrninpoHover

Gnpe Lonclaltl.rr_y

H4 + Mt GoodwinHyland Bay

Fossil I-lead

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

Synrift

GEOHISTORY PLOT: Petrel 2

100 2.0

---- 80 3.0

20 7.0

TIME (Ma)200^150350^300^250 100^50

1201.0

4.060

5.0

406.0

Heat Flow^ireTectonic Subsidence 41.(Min/Max Range)^+

I PERMIAN f TRIASSIC I^JURASSIC CRETACEOUS TERTIARY

0

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Petrel 2

0.0

© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^

95

100 050TIME (Ma)200^150

VR (LOG SCALE)0.2^0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

Key :VP^•TAI (?VR-Source) •TmaxTmax (?)VP Rob ResSCI (VP Equiv)

Bathurst Island

Flamingo

Plover

Malita

Cape Londonderry

H4 + Mt Goodwin

Hyland Bay

Fossil HeadTop DrriSas Maturity Zone @ 4535 m.


5.0OBSERVED vs COMPUTED MATURITY PLOT: Petrel 2

Dry Gas

Tertiary

250350 300

Marone° Oil (in situ) EsOil (expelled) •Gas (in situ) IllGas (expelled)

Mover

an '55 lcorlorderry

14. MI Cvocrevon

Hvemd E.v

•^I

1^ 111/11t,t41.11,,12110

Del CARBONIFEROUS PERMIANIFTRIASSICI^JURASSIC^CRETACEOUS I TERTIARY I0 Bathurst Island

Fossil Head

Hyland Bay: Oil Expelled = 0, Gas Expelled = 12 bbl equiv/m2


Kuriyippi

Tanmurra

20

Synrift

Point Spring

5 Keyling

Treachery

Strat.^Source Rocks

HYDROCARBON GENERATION PLOT: Petrel 2

_6.0

_5.0


CARBONIFEROUS


Sea Level^—Sediment Interface WISO-Ro

GEOHISTORY PLOT : Tern 1

avvvalovi.n.ru

Bathurst Island

e

H4 + Mt Goodwin

Hyland BayFossil Head

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

Synrift

TIME (Ma)350

a^.300

I250

I200

I150^100^50

1^ .Î^. 0.0

120

1.0

100

2.0

80

n

60

4.0

40

5.020

Heat Row •I PERMIAN TRIASSICÎ JURASSIC CRETACEOUSÎ^TERTIARY

Tectonic Subsidence(Min/Max Range)

Present Heatflow = 56.451 (mW m-;

0

HEATFLOW AND TECTONIC SUBSIDENCE PLOT : Tern 1

96


97

350 300 250TIME (Ma)200^150

VR (LOG SCALE)0.2^ 0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

TertiaryswironekrinnA,

Bathurst Island

Flamingo

Plover

"ÂnAnnAttruCape Londonderry

OBSERVED vs COMPUTED MATURITY PLOT : Tern 1

4.0

H4 + Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

100 50 0IÎ^ I^ 1^ •^1^ IIÎ^1Î^1Î Da CARBONIFEROUdiPERMIA4TRIASSIC I^JURASSIC^(CRETACEOUS I TERTIARY 1


.Y.d Bey

KeylingKen.ng

Kuriyippi

Point Spring

0Strat.^Source Rocks

Flearnent,o

A0.14344,"2

Bathurst Island

Fossil Head

Treachery

10

12

Tanmurra

Synrift


1.14 • MI Ocodwm

Hyland Bay

HYDROCARBON GENERATION PLOT : Tern 1

_ 0.0

_ 6.0

_ 5.0

Oil (in situ)ÊlOil (expelled) •Gas (in situ) ElGas (expelled) 0


98

•••

DE

0.0

0.50.6

0.7

1.0

0.

1.0

1.3

1.6

Sea Level^—Sediment Interface BSISO-Ro

AtlinfgriallEnifiktilitightingsatifIv a„ rt."^.21.1WNWV

Milligans praecipua

_5.0

Tertiary.0.0.013.0,D4D1243.

Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point SpringTennnara 2

-rvvnialtrfluvs"

Ningbing

Cockatoo

GEOHISTORY PLOT : Turtle 2

2.5TERTIARY

TIME (Ma)350^300^250^200^150 100

0.0

20Heat FlowTectonic Subsidence 0.(Min/Max Range)^4-

Present Heatflow = 57.788 (mW m.. 2) 3.0

40

El^CARBONIFEROUS^I PERMIAN I TRIASSIC I^JURASSIC CRETACEOUS

160

140

120

100

------- 80

60

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Turtle 2


•••••••••••••••

•••••••••••••••

VR (LOG SCALE)0.2^ 0.5^0.6 0.7 0.8^1.0 1.3 1.6 2.0 2.5 3.2^4.0

I^1 IÎ I I I I IÎ

-0.5Oil and

Gas Key :VR^•TAI Foster t

Tertiary 0.0 Tmax

rarkfteVuNftn.rtru

Hyland Bay

Fossil Head

KeylIng 1.0 -

Treacheryr.:5^1.5 -cc)

• ow

Kuryippi co

2.0

Point Spring Top Oil and Gas Maturity Zbne e

Tanmurra 22.5 — tits,JVVVVVVVNIVNI • i .e.._ -

Milligans praecipua Base Oil and Gas Maturity Zone 0 2781 m.

3.0 —.011.1VVVVVVV1.1

Langfielcl

Ningbing

3.5 .Cockatoo


OBSERVED vs COMPUTED MATURITY PLOT : Turtle 2

HYDROCARBON GENERATION PLOT : Turtle 2

_6.0

5.0

CS

3.0 =—^•3

_ 2.0

TIME (Ma)350^300^250^200^150^100^50

Strat.0.0 -^Tertiary

-1P.Aftrovvtrk

' Hyland Bay

0.5 —." Fossil Head

Source Rocks^1^. .^ ..., 1DEI CARBONIFEROUSLIPERMIANÎ

IITRIASSIC^JURASSIC

Oil (in situ) /21Oil (expelled) 11/Gas (in situ) ElGas (expelled) Ei

• IÎÎÎÎ CRETACEOUS l TERTIARY

to 7Keyling

— Treache ry1.5.^

-^Kuryippi—

COI 2.0.

=- Point Spring

Tanmurra 2 L J^2.5 „vi„,ato,„,,^

Milliganspraecipua

3.0.Langfield

Ningbing

3.5 .^Cockatoo

Mid Milligans: Oil Expelled = 0, Gas Expelled = 3 bbl equiv/m2

99


350 300 250TIME (Ma)200^150

^100

CARBONIFEROUS PERMIAN TRIASSIC^JURASSIC^CRETA

50

1.3

1.6

2.0

2.5

3.2

4.0


Sea Level^—Sediment InterfaceISO-Ro

Tertiary

Cape Londonderry

H4 + Mt Goodwin

I-Iyland Bay

Fossil Head

Keylingt.acivoy

Kuryippi

Ppm Ox1,0

Tanmurra 2

Tanrnurra

Milligans

Synrift fan Delta

GEOHISTORY PLOT : AGS0/1-SP3400

TIME (Ma)350

.300^250

I^.200 150 100^50

..^...0

0.0

120_ 0.5

1.0_100

-_ 1.5ri

80 -_ 2.0

rTI- 2.560 r,

3.0 E7•^3

40 3.5

_ 4.0

20I CRETACEOUS1ZZ •■^ZO I PERMIAN SSIC TERT 4.5

Heat FlowTectonic Subsidence •(Min/Max Range)^+

56.171 (m)N m-2)[Present Heatflow 5.00

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: AGS0/1-SP3400

7-

100


101

VR (LOG SCALE)

^

0.5 0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5^3.2 4.0IÎÎ Î^lilt

and Ges

0.2

Top Oil and Gas Maturity Zone 0 2468 m.

Base Oil and Gas Maturity Zone @ 3329 m.

NO OBSERV


MATURATION DATA

Tertiary

Cape Londonderry

H4 + Mt Goodwin

Hyland BayFossil Head

KeylingTreAche,

Kuryippi

PO,I SP(O

Tanmurra 2

Tanmurra

Milligans

Synrift fan Delta

OBSERVED vs COMPUTED MATURITY PLOT: AGS0/1-SP3400

10

TIME (Ma)^350^300^250^200^150

Strat^Source RocksÎÎÎ^•Î100 50 0

7.0_0 Tertiary DEI CARBONIFEROUS IPERMIANITRIASSIC I^JURASSIC I CRETACEOUS I TERTIARYÎ

Cape Londonderry Oil (in situ)ÊnH4 + Mt Oil (expelled)^•Goodwin Gas (in situ)

Gas (expelled) 0 _ 6.0Hyland Bay

2Fossil Head

Keyling

- 5.00a-

Kuryippi Hyland Bay: Oil Expelled^0, Gas Expelled -^0 bbl equiy/m2

4 3co

Point Spnnp

_ 4.0 g:Tanmurra 2 CD

z •6 33.0 NZ

Tanmurre I

MilligansMt11,3ans

Keylinq: Oil Expelled =^0, Gas Expelled =^0 bbl equiv/m2 nx)•

8 L 2.0 E

Synrift fanDelta

• 1. 010

Mid Milfigans: Oil Expelled = 24, Gas Expelled =^18 bbl equiv/m2 0.0



102

TERTIARY^IC 33CRETACEOUS

TIME (Ma)200^150350 300 250 100 50

Iwjky,,,NrwvCape Londonderry

0.0

1.0


Sea Level^—Sediment Interface MISO-Ro

"AnAT6,51.1.covu

H4 • Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

GEOHISTORY PLOT : AGS0/5-SP2800

TIME (Ma)

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: AGS0/5-SP2800

0.0

_ 0.5

_1.0

L

2.5 —

100

0

120

7.0

350^300^250^200^150 100 50,^ .^.^.^1^.^.^,^.1^,

40 -

20 - ,DE4^CARBONIFEROUS^I PERMIAN I TRIASSIC I^JURASSIC

0Present Heatflow = 53.786 (mW rn.. ,): 4.0

Heat Flow

^

Tectonic Subsidence IF^

TIME

Range)^+

3.0

© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^

103

100 50 0TIME (Ma)200^150

VA (LOG SCALE)0.2^ 0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

Cape Londonderry„trava.KAAAA,

Terenry,,

Top Dry Gas Maturity Zone 4837 m.


H4 + Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

OBSERVED vs COMPUTED MATURITY PLOT: AGS0/5-SP2800

300 250350

0.0 vvaaplarti,,,

Keyling Keyling

I^1^L , 1^ I^1 DE1 CARBONIFEROUS [PERMIAN' TRIASSIC/^JURASSIC^(CRETACEOUS 1 TERTIARY 1

Cam La...decry

H4 + MtGoodwin

Hyland Bay WU. Bev

Fossil Head

Treachery

Kuriyippi

Point Spring


Tanmurra


Strat.^Source Rocks

1.0

2.0

7.0

6.0


6.0

_ 5.0

4 0 a3CD

•

2.0 aCD

CD

1.0

0.0

Oil (in situ) ElOil (expelled) 11111Gas (in situ) MIGas (expelled) D


104

1.31.62.02.53.24.0



TIME (Ma)350^300^250^200^150^100^50

- e.. --e..., i,, v, ,Is^r•^oal IIIMIN•111 _ •Palaeocene-01,1.one

Bathurst Island

Plover

Cape Londonde,Ha Mt Goodwtrt

Hyland Bay

Fossil Head

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

GEOHISTORY PLOT: AGS0/7-SP1100

TIME (Ma)200^150250350 300 100

120

100

— 80

60

40

20

Heat FlowTectonic Subsidence ill(Min/Max Range)^+

I PERMIAN I TRIASSIC I^JURASSIC^J^CRETACEOUS

Present Heatfiow = 55.316 (mW ma1 9.0

HEATFLOW AND TECTONIC SUBSIDENCE PLOT : AGS0/7-SP1100


VR (LOG SCALE)02^ 0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

Top Dry Gas Maturity Zone @ 5134 m.


Peleacoone.01,mene

Bathurst Island

1.binentl0

Plover

Cane LondondenN

H4 + Mt GoodwinHyland Bay

Fossil Head

Keyling

Treachery

Kuriyippi

Point Spring

Tanmurra

OBSERVED vs COMPUTED MATURITY PLOT : AGS0/7-SP1100

TIME (Ma)350^300^250^200^150^100^50

Strat.^Source Rocks^ I^.ÎÎtÎIÎ

06.0_

Palaeocene-01 Celle CARBONIFEROUS IP'El4MIANI TRIASS IC I^JURASSIC^CRETACEOUS^TERTIARY

Bathurst Island Oil (in situ)ÊIOil (expelled)^111

MOO*. Gas (in situ)Plover Gas (expelled) 0

5.0_Cape Londonderry

KS 4. Mt Goadran

5 Hyland Bay

. Fossil Head

Keyling _4.0Treachery PC,

10CD

3.0 =.•Hyland Bay: Oil Expelled =^0 Gas Expelled = 87 bbl equiv/m2

3Kuriyippi

15L.L.1Ca) _2.0

Point Spring

20 _ 1.0

Tanmurra

25 0.0Keyling: Oil Expelled =^40, Gas Expelled = 146 bbl equiv/m2


105


106

.^"TvPv7SZKA.,,,

-o

0.0

1.0

2.0

3.0

6 —P6egfrI4d0

Keyling

Treachery

Kuryippi

Pant Spn,TartmutrA 2

Milligans A5-8

Milligans A1-4

Ningbing

Cockatoo

GEOHISTORY PLOT: CB81 -1 1 a

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: CB81-11a

100 50

CRETACEOUS TERTIARY

350^300^250.Î^. •Î.Î

TIME (Ma)200^150

IîÎ

120

100

80 -

60

40

-r

20 Ekl^CARBONIFEROUS I^PERMIANÎ^TRIASSIC I JURASSIC

Heat FlowTectonic Subsidence O.(Min/Max Range)^+

0 —

00.0

_ 0.5

_ 1.0

Present Heatfiow 55.652 (mw

3.5

4.0


107

VR (LOG SCALE)0.2^0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

I^IOil and

Gas

Top Oil and Gas Maturity Zone @ 1632 m.


"

20

3.0

4.0

5.0

6.0

7.0

0.0

1.0

•■■

Keyling

Treachery

Kuryippi

Pqnt Sprang

Tnnrnurre 2

Milligans A5-8

Milligans A1-4

Ningbing

Cockatoo

OBSERVED vs COMPUTED MATURITY PLOT: CB81-11a

HYDROCARBON GENERATION PLOT: CB81-11a

250 100 50350 300 _6.00.0

_5.01.0

2.0

TIME (Ma)200^150

6.0

7.0

04.0 -_3CD

••

2.0 c„--_

1.0

0.0

Strat.^Source Rocks 11.410^1122^ •1..0211

( CRETACEOUSCARBONIFEROU IPERMIANITRIASSIC I^JURASSIC^CRETACEOUS I TERTIARY

Ningbing

Keyling

Treachery

Kuryippi

Point SP.0

Tenrnurre 2

.„‘Tkr. 'n.rtni. Rntr

Milligans A5-8

Oil (in situ)^ElOil (expelled) •Gas (in situ)Gas (expelled) 1:1

Mid Milligans

Milligans A1-4

Cockatoo

Mid Milligans: Oil Expelled = 19, Gas Expelled = 15 bbl eguiv/m2


0.0

1.0

2.0

3.0nn—C)

4.0 ci")co

r-rt5.0

a

7.0

8.0

Tanmurra

JVVVVVVVVVV

Milligans

.rnsWt.41114.inrundMaturity Method : Kinetic

Sea Level^—Sediment Interface leISO-Ro

Cockntoe

9.0

AittetitettetitH4 -I- Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

GEOHISTORY PLOT: HD16-SP400

350^300^2501^ .^ . . 1

50.^.^ 1 0.0

160_0.5

140

_ 1.0

120-,rn

1.5 io„

loo

:%"'•

i■-•••

_2.0^r..r1

-0

12.5`‹C 3

60:

3.0

CARBONIFEROUS I PERMIAN^1^TRIASSIC^I JURASSIC I CRETACEOUS TERTIARY 3.520.

Heat FlowTectonic Subsidence *(Min/Max Range)^+

Present Heatflow 55.100 (mIN m- ,e) 14.0—0

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: HD16-SP400

100TIME (Ma)

150200

108

AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION

109

250350 300TIME (Ma)200^150

VA (LOG SCALE)0.2^ 0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0

Tanmurra

.Art.n.n.rvvvvvu

Milligans

Jvvvl.gwvvvIu

Cctlin leo

Oil andGas

Top Oil and Gas Maturity Zone @ 2169 m.2.0

6.0

7.0

NO OBSERVE) MATURATION DAT

0.0

1.0

ftottftfiftwodH4 + Mt Goodwin

I-Iyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

OBSERVED vs COMPUTED MATURITY PLOT: HD16-SP400

100 50 0Strat.^Source Rocks

0.0 --Ngtaitiftft

H4 + MtGoodwin

1.0 Hyland Bay Hyland Bay

Fossil Head

2.0 Keyling <4_ay_g_t

Treachery

30Kuryippi

•CC

Point Spring(1,-)co

4.0

5.0Tanmurra

L.6J

...R.A.ft"."11.01A

6.0

Milligans Mid Millidads

7.0

Ninqbinq8.0 CocVateo


1.

1^1^1^ 1^$^•^1ÎÎ^)Î^,l^ t^ I

^DEI CARBONIFEROUS IPERMIANITRIASSIC I^JURASSIC^( CRETACEOUS I TERTIARY


CD


Mid Milligans: Oil Expelled = 19, Gas Expelled = 13 bbl equiv/m2

_ 0.0

_7.0

6.0

_1.0

Oil (in situ)ÊlOil (expelled) •Gas (in situ)Gas (expelled)


110

•••

0.0

1.0


7.0

Jwritri.rkr...nrywvuH4 + Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

Tanmurra

Arurtn.nrimuy

Milligans

y'ivVrArs'Arut

GEOHISTORY PLOT: HD16-SP1050

100 50TIME (Ma)

350^300^250^200^1501^.Î^.^,Î^,Î^•^t

Present Heatfiow = $4.380 (nYv'V

HEATFLOW AND TECTONIC SUBSIDENCE PLOT: HD16-SP1050


•••••••••••••••••••••••••••••••

Tanmurra

Milligans

ANNAAAAAIWSynrift Maturity Method : Kinetic

6.0

OBSERVED vs COMPUTED MATURITY PLOT: HD16-SP1050

VR (LOG SCALE)0.2^ 0.5 0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5^3.2 4.0

Oil andGas

0.0IlAINP.MAJW4H4 + Mt Goodwin

Hyland Bay

Fossil Head

Keyling

Treachery

Kuryippi

Point Spring

1.0

• 2.0•

L.L.1

3.0

L.LJ

4.0

5.0

TIME (Ma)350^300^250^200^150 100^50^0

Strat.^Source Rocks^I.^.^.^...,I....I ..I..^LIIIINI 7.00.0 Te i D CARBOIFEROUS)4411 .A4TRIASSIC1 JURASSIC CRETACEOUS I^TERTIARY

-,VMMAYNA Oil (in situ)^BEIGoodwin Oil (expelled)^IIII

- Hyland BayGas (in situ)^MIGas (expelled) El _6.0

1.0 Fossil Head

Keyfing 5.0-^<0Treachery

CD

g_4.0Kuryippi

CI)a

•3.0 . Point Spring1

ci)33.0 rs-1 ...._.-• .

Tanmurra 0CI

4.0

5.0: Milligans _ 1.0Mid Milligans

Mid Milligans: Oil Expelled =^19. Gas Expelled =^14 Obi equiv/m2"Vvvvvv‘AA_ Synrift 0.0

6.0


1 1 1


••••••••••••••

112

•0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

••••••••••••••••••

113

Appendix C: Kerogen Kinetic Data

• The following kerogen kinetic analyses were undertaken by AGSO' s Isotope and Organic GeochemistryLaboratories (see Edwards & Summons, 1996, appendix A).

• Modelled kerogen for Milligans source unit based on sample #7925• Modelled kerogen for Keyling and Hyland Bay source units based on sample #8484

•

411^Sample #8539:Extracted Rock, Spirit Hill-1, 199 m, Milligans Supersequence, Shale

•TOC = 1.71 %, HI = 60

Frequency factor = 5.8204E +12 s -1

Percent^Activation energy (cal/mol)0.00 42000.0.46 43000.0.82 44000.1.50 45000.0.00 46000.0.00 47000.0.00 48000.0.00 49000.42.75 50000.17.78 51000.9.06 52000.0.00 53000.2.94 54000.6.31 55000.0.00 56000.0.00 57000.8.38 58000.

Sample #8539:Carboniferous Kerogen, Spirit Hill-1, 199 m, Mffiigans Supersequence.

Frequency factor = 3.3389E +13 s-1

Percent^Activation energy (cal/mol)0.00 44000.0.00 45000.0.84 46000.0.93 47000.1.81 48000.0.89 49000.0.00 50000.0.00 51000.43.83 52000.15.45 53000.30.04 54000.0.00 55000.0.47 56000.2.00 57000.0.00 58000.2.16 59000.0.00 60000.1.58 61000.


04110•

••••

•

•••

•

•

114

Sample #8544:Extracted Rock, Spirit Hill-1, 670-671m, Ningbing Supersequence, ShaleTOC = 0.73%, HI = 123


Percent^Activation energy (cal/mol)0.00 43000.0.05 44000.0.00 45000.0.20 46000.1.76 47000.0.00 48000.0.00 49000.0.00 50000.0.00 51000.0.00 52000.55.61 53000.18.53 54000.8.80 55000.0.00 56000.7.41 57000.0.00 58000.0.00 59000.0.00 60000.7.65 61000.

Sample #8544:Devonian Kerogen, Spirit Hill-1, 670-671 in, Ningbing Supersequence


Percent^Activation energy (callmol)0.00 45000.0.92 46000.0.00 47000.0.20 48000.2.92 49000.0.00 50000.3.85 51000.0.00 52000.0.05 53000.29.97 54000.21.25 55000.35.62 56000.0.00 57000.0.31 58000.0.62 59000.0.00 60000.0.00 61000.4.30 62000.


115••• Sample #8484:

Permian Extracted Rock, Flat Top-1, 1661-1664 m, Keyling Supersequence, Coal• TOC = 31%, HI = 295

• Frequency factor = 1.1663E +14 s-1

Percent^Activation energy (cal/mop• 0.00^46000.

0.00^47000.• 0.00^48000.

0.00^49000.

• 0.00^50000.0.00^51000.

• 0.00^52000.0.00^53000.

• 66.84^54000.0.00^55000.

• 15.56^56000.3.68^57000.

• 5.34^58000.3.52^59000.

• 0.00^60000.2.85^61000.

• 0.00^62000.2.21^63000.•

••

•

•

Sample #8989:Permian Extracted Rock, Kinmore-1, 1470-1473 m, Keyling Supersequence, ShaleTOC = 6.65 %, HI = 283


Percent^Activation energy (calhnol)

•0.000.00

46000.47000.

• 0.000.00

48000.49000.

0.00 50000.• 0.00 51000.

0.00 52000.lb 0.00 53000.0.00 54000.

• 63.99 55000.0.00 56000.

• 15.62 57000.7.34 58000.

III 5.55 59000.0.00 60000.

• 1.81 61000.0.00 62000.

• 0.00 63000.5.69 64000.

411III•

^0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^•

•116 •

••

Sample #7925:Extracted Rock, NEF1002, 208 m, Mililgans Supersequence, Shale^ •TOC = 3.67 %, HI = 292


Percent^Activation energy (cal/mol)0.00 43000.0.00 44000.0.00 45000.0.00 46000.0.00 47000.0.00 48000.0.00 49000.0.00 50000.90.68 51000.0.27 52000.9.05 53000.0.00 54000.0.00 55000.0.00 56000.0.00 57000.0.00 58000.

•

@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^•

117

Oil versus Gas Bond Frequencies

Since the bulk chemical kinetics for the Milligans Bed kerogen (# 7925) is dominated by asingle activation energy at 51 kcal/mole with a bond frequency of 300 mg HC/gTOC (equal toRock Eva! HI), the proportion of the bond frequencies that is gas (C1-05 hydrocarbons) and oil(C6, hydrocarbons) was determined by pyrolysis - gas chromatography - mass spectrometry(py-gc-ms), as plotted below. Using external gas standards for quantitation, the amounts ofgas and oil were calculated to give a gas-to-oil ratio (GOR) of 0.5. Using this GOR value,bond frequencies of 100 and 200 mg HC/gTOC were applied to the kerogen-to-gas andkerogen-to-oil WinBury kinetics.

File:7E6AU1513 #1-6382 Acq:15-AUG-1996 11:13:11 Septum El+ Magnet 70STIC-16.7_18.5 (+RP) Mer Def 0.25File Text: AGS007925 Milligans Bed; 300-550°C 43 , 50C/m in; em2.6; 10.6m g

C 2-05

(11.69 gg)

C 6 + (27.96 gg)

Methane (C 1 ; 2.54gg)

500^ 1000^ 15.100^ 20'100^ 25:00^Time (minutes)

Pyrolysis - gas chromatography - mass spectrometry trace of kerogen concentrate # 7925.

In the case of the modelled Keyling and Hyland Bay kerogens, the proportion of the bondfrequencies that is gas (CI-CS hydrocarbons) and oil (C6+ hydrocarbons) was determined byanalogy to similar Gondwanan source rocks in the East Australian Basins (C.J. Boreham,AGSO, July 1996).


118

••••

N0

&Intim

6*7

RateConstant

BondFrequency

Reactant

C4'6'

Proixt

C"'

1 1 51 6.7E+0026 180.00 1 2

2 2 51 6.7E+0026 90.00 1 5

3 3 52 6.7E+0026 2.00 1 2

4 4 52 6.7E+0026 1.00 1 5

5 5 53 6.7E+0026 18.00 1 2

6 5 53 6.7E+0026 9.00 1 5

7 5 66 3.5E+0029 50.00 2 5

KINETICS: MILLNEF.DT2

Kerogen kinetic data modelled for the mid-Milligans source unit.

^@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^

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62 64 6650^52^54^56^58^60Activation Energy

KEROGEN (MILLNBF.DT2)

180Kerogen -> OilOil Gas 8, ResidueKerogen Gas

160

140

120

>, 100c

80

60

40

20

PAY

••••119

N0

Iataln.En"W

RateConstant

BondFrequency

n0•21111

''''''Rota"

1 1 54 3.6E+0027 120.00 1 2

2 2 54 3.6E+0027 80.00 1 5

3 3 56 3.6E+0027 23.00 1 2

4 4 56 3.6E+0027 23.00 1 5

5 5 58 3.6E+0027 11.00 1 2

6 6 58 3.6E+0027 17.00 1 5

7 7 59 3.6E+0027 4.00 1 2

8 8 59 3.6E+0027 6.00 1 5

9 9 61 3.6E+0027 16.00 1 5

10 10 66 3.5E+0029 50.00 2 5

KINETICS: KEYLING.D12

Kerogen kinetic data modelled for the Keyling source unit.

••© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

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••

BURYWWI 1 IKEROGEN (KEYLING.DT2)••••••

64 66

100

80

40

20

0

120Kerogen -> OilOil -> Gas & ResidueKerogen -> Gas

••••••••••

120

••••

KEROGEN (HYLAND.DT2) PRY

N0

Ad.,2.'"W

RateConstant

BondFrequency

Rea=9

c`d°Praia

c'''

1 1 54 3.6E+0027 60.00 1 2

2 2 54 3.6E+0027 40.00 1 5

3 3 56 3.6E+0027 11.50 1 2

4 4 56 3.6E+0027 11.50 1 5

5 5 58 3.6E+0027 5.50 1 2

6 6 58 3.6E+0027 8.50 1 5

7 7 59 3.6E+0027 2.00 1 2

8 8 59 3.6E+0027 3.00 1 5

9 9 61 3.6E+0027 8.00 1 5

10 10 66 3.5E+0029 50.00 2 5

KINETICS: HYLAND.DT2

Kerogen kinetic data modelled for the Hyland Bay source unit

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•© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^

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I^I

64 66

50

40

Kerogen OilOS -> Gas & ResidueKerogen -> Gas

60

20

1 0

petrel sub-basin study 1995-1996 geohistory modelling

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