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AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
PETREL SUB-BASIN STUDY
1995-1996
GEOHISTORY MODELLING
by
John M. Kennard
AGSO RECORD 1996/43
i i
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.
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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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.
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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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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^© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^•
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•LIST OF FIGURES^ page
•
• 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
•
•
• 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.
••
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^
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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.
@ AUSTRAUAN GEOLOGICAL SURVEY ORGANISATION ^
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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.
•••••••• ^ AUSTRAUAN GEOLOGICAL SURVEY ORGANISATION•
4
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.
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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.
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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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.
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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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).
•
• © AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION^
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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.
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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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 •
••
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
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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).
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
•— 200— Contour of estimated erosion (m)
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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.
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
•••
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
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
•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.
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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
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CRETACEOUSI^t^1^1^1^1^•^
1^ a^IDEVONIP1^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.
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
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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.
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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.
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24
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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 b^equiv/m2 1.0Gas Expelled = 8^I 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
6.0^I ^.IDE/oi litAABolliFtRobs 11^'^il^"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.
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26
I 1 111 1 111 II^1*R 9 6 0 4 3 0 9 *
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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%
HYDROCARBON GENERATION PLOT: HD16-SP1050
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.
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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 SI^I^CRE A EO^ 1S^I^E 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 015S^I^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.
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I
I I II
I II
II II
* R 9 6 0 4 3 1 3 *
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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^• I^illits•gclee^I^A.Inr41.•AlcrsAc^I•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.
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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‘e^AQC f^I I^ItbA4C1(?^I .1:10rAdF(16S^I 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^, ^A
•1^ 1 ^5.0
E 01 A BO IF RO S^P R A^RASSC I^J ASSIC^I^GRE,TA EOUS^I^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.
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1 1
II II 1 1
II I
* R 9 6 0 4 3 1 7*
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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^"TRIlaselc^I^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^.^k^I^.,.
100 50 05.0
bEJoi^AABotliFRots PR^AN'^HIASSIC^I^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.
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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 *
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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).
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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
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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.
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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.
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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
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42
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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
Oil Expelled = 40 bbl equiv/m2Gas Expelled = 112 bbl equiv/m2TR varies from 98 to 100%
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.
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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)^InGas (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
Oil Expelled = 34 bbl equiv/m2Gas Expelled = 35 bbl equiv/m2TR varies from 82 to 86%
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•^I^• ,^I ,^ A^ARN'E 01 AABOINIIFtROUS^PtRMIAN^"TRIASSIC^JURASSIC^I^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.
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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
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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
•
Oil Expelled = 0 bbl equiv/m2Gas Expelled = 10 bbl equiv/m2TR varies from 30 to 46%
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%
HYDROCARBON GENERATION PLOT: AGS0/5-SP2800
- 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
Oil Expelled = 98 bbl equiv/m2Gas Expelled = 133 bbl equiv/m2TR varies from 98 to 100%
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.
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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%
Keyling (3400.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG = 5.00%
HYDROCARBON GENERATION PLOT : Penguin 1
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
Keyling (3400.0 m.KB, 200.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG = 10.00%
4.5
HYDROCARBON GENERATION PLOT : Penguin 1
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.
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
1!IR 111 1 1 1111 11 j0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
TI ME (Ma)360^300^250^200^150^100^50^0
k^a^a^A. A ...,^I^A^a^i^A_^A •5.0E 01 A BO IF RO S^P R Ali.^...TRI
, ASSIC^I I^
JURASSIC^I^GRETA EOUS^I^Eitti 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%
HYDROCARBON GENERATION PLOT: AGS0/5-SP2800
TIME (Ma)350^300^250^200^150^100^50^0
,^A ^.E\01 A BO IF RO S^P R A^R ASS C^J A SI^I^GRETA FOOS^TATIARY
, ^5.0
Oil (in situ)^ijOil (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
Keyling (2650.0 m.KB, 300.0m. thick) Genetic Potential = 300.00 mg/gm TOG, TOG = 10.00%
HYDROCARBON GENERATION PLOT: AGS0/5-SP2800
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.
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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.
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•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
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•
•••••
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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.
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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.
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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.
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
* R 9 6 0 4 3 3 5 *
TIME (Ma)350^300^250^200^150^100^50^0.^I^,_
^
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%
HYDROCARBON GENERATION PLOT: AGS0/7-SP1100
TIME (Ma)350^300^260^200^150^100^50^0
, ^A ^5.0E 0, A BO IEE 0 S^136110Ale^'"I'FlIASSIC^I^J ASSI
j,^,C^I^CRETA OUS^I^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 ^
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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.
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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 (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.
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• 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.
•
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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.
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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
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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.)
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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
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•••
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^,^I^,^I^,^.^I^.^1 100 50
0.0
160
140
120
z_:-- 80
0 -
40-0E1^CARBONIFEROUS^I 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
O AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
••••
••••••
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.^as^auriy one 0
?Ningbing3.0 7
?Cockatoo- Maturity Method : Kinetic
OBSERVED vs COMPUTED MATURITY PLOT: Barnett 2
TIME (Ma)350^300^250^200
Strat^Source Rocks^I^ I/^•^I^I^I
150II
100 50^06.0
0.0 DE' CARBONIFEROUS [PERMIAN' TRIASSIC' JURASSIC (CRETACEOUS1 TERTIARY^I
TertiaryOil (in situ)^IM
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
72
TIME (Ma)350^300^250^200^150 100^50I^ 1^III
PDEI CARBONIFEROUS I PERMIAN I TRIASSIC I(
^
JURASSIC^I •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
CARBONIFEROUS^I 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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
73
02VR (LOG SCALE)
0.5 0.6 0.7 0.8 1.0^1.3 1.6 2.0 2.5^3.2 4.0I^I^I^I
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[21111^It^ I^.11^Ij.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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
Maturity Method : Kinetic
Sea Level^—Sediment Interface 111ISO-Ro
GEOHISTORY PLOT: Bonaparte 2
TIME (Ma)
350^3001^I
250, •^,^•^• .
200 150 100 50I^I^.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 TERTIARY^IC. 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
O AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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.
Maturity Method : Kinetic
Fossil Head
Keyling
Treachery
Kuryippi
Point Spring
TantnUfra 2
f=1
Bonaparte
Basement
77
OBSERVED vs COMPUTED MATURITY PLOT : Cambridge 1
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
80
TIME (Ma)350^300^250^200^150 100^50
40
20
p^ItI^1^I^1^II^I^ I,.^•^I. ^I^I,,I^IL •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
Sea Level^—Sediment Interface •ISO-Ro
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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 Rocks^I^ I^I I I _6.00.0
-"MACVrthtf' DB CARBONIFEROUS IPERMIA^TRIASSIC!^JURASSIC CRETACEOUS I TERTIARYTanmurra 2
Oil (in situ)^laOil (expelled)^IIIGas (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
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
82
100 50 00.0•
TIME (Ma)350^300^250^200^150
I^•^I^I^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
Maturity Method : Kinetic
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 PERMIAN^I TRI SIC I JURASSIC CRETACEOUS TERTIARY 2.5
20 ^
^
Heat FlowTectonic Subsidence 11-(Min/Max Range)^+
HEATFLOW AND TECTONIC SUBSIDENCE PLOT: Keep River 1
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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 4.0I^I^I^I^lift^II
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^••^I
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
2.5TERTIARYCRETACEOUS
_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
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
Maturity Method : Kinetic
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
Maturity Method : Kinetic
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
2.5TERTIARYCRETACEOUS
_ 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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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
Maturity Method : Kinetic
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^ 11111101,14^I1^ )
50 0_ 6.0
0.02'416111109".01111a..
DEI CARBONIFEROUSLIPERMIANITRI ASSICI JURASSIC^CRETACEOUS I TERTIARY^I
:(1‘1121'144.o
;■;;,:V advIllfkrkn Oil (in situ)^cmOil (expelled)^•
0.5 Hyland Bay Gas (in situ)^isGas (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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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\
Maturity Method : Kinetic
Sea Level^—Sediment Interface 2ISO-Ro
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
I^I II^I^t0.2
-0.5
Tertiary
Ann.rwtrtAnniu
MalitaxvvNA.A.A.rtfkrueu
Cape Londonderry
C_LaJ
H4 + Mt Goodwin
Hyland Bay
Fossil I-lead
Maturity Method : Kinetic
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
I^II^I^I^I^ I^II^•^I^/^I
IPERMIANI TRIASSIC I^JURASSIC
100)^II^I^I
50I _ 6.0
0jgatir?r'srrAal7s
DEI CARBONIFEROUS I CRETACEOUS I TERTIARY
nMower Oil (in situ)^Ea
Oil (expelled)^•Gas (in situ)^El
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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.^„^,^I
00.0
1.0
2.0
3.0
4.0
-13
5.09
6.0
7.0
PERMIAN I^TRIASSIC JURASSIC I CRETAC oi* S^I^• =.
Present Heatfiow = 55.167 (mW m- 2) 8.0
350^300.^I^.^.^.
120
100
80 -^
40 -
20
Heat Flow^*STectonic Subsidence •11-
I
(Min/Max Range)^+
0
O AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
•
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.
Maturity Method : Kinetic
Cap, London:bevy
114 + Mt GoodwinHyland Boy
Fossil Head
Keyling
Treachery
Kuriyippi
Point Spring
Tanmurra
Synrift
OBSERVED vs COMPUTED MATURITY PLOT: Petrel 1A
93
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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.
Maturity Method : Kinetic
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
Keyling: Oil Expelled = 40, Gas Expelled = 112 bbl equiv/m2
Kuriyippi
Tanmurra
20
Synrift
Point Spring
5 Keyling
Treachery
Strat.^Source Rocks
HYDROCARBON GENERATION PLOT: Petrel 2
_6.0
_5.0
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
CARBONIFEROUS
Maturity Method : Kinetic
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^ .^I^. 0.0
120
1.0
100
2.0
80
n
60
4.0
40
5.020
Heat Row •I PERMIAN TRIASSIC^I JURASSIC CRETACEOUS^I^TERTIARY
Tectonic Subsidence(Min/Max Range)
Present Heatflow = 56.451 (mW m-;
0
HEATFLOW AND TECTONIC SUBSIDENCE PLOT : Tern 1
96
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
"^AnAnnAttruCape Londonderry
OBSERVED vs COMPUTED MATURITY PLOT : Tern 1
4.0
H4 + Mt Goodwin
Hyland Bay
Fossil Head
Keyling
Treachery
100 50 0I^I^ I^ 1^ •^1^ II^I^1^I^1^I Da CARBONIFEROUdiPERMIA4TRIASSIC I^JURASSIC^(CRETACEOUS I TERTIARY 1
Hyland Bay: Oil Expelled = 0, Gas Expelled = 3 bbl equiv/m2
.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
Keyling: Oil Expelled = 34, Gas Expelled = 35 bbl equiv/m2
1.14 • MI Ocodwm
Hyland Bay
HYDROCARBON GENERATION PLOT : Tern 1
_ 0.0
_ 6.0
_ 5.0
Oil (in situ)^ElOil (expelled) •Gas (in situ) ElGas (expelled) 0
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
•••••••••••••••
•••••••••••••••
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 I^I I I I I I^I
-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
Maturity Method : Kinetic
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 CARBONIFEROUSLIPERMIAN^I
IITRIASSIC^JURASSIC
Oil (in situ) /21Oil (expelled) 11/Gas (in situ) ElGas (expelled) Ei
• I^I^I^I^I 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
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
Maturity Method : Kinetic
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
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
101
VR (LOG SCALE)
^
0.5 0.6 0.7 0.8^1.0^1.3 1.6 2.0 2.5^3.2 4.0I^I^I ^I^lilt
and Ges
0.2
Top Oil and Gas Maturity Zone 0 2468 m.
Base Oil and Gas Maturity Zone @ 3329 m.
NO OBSERV
Maturity Method : Kinetic
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 Rocks^I^I^I^•^I100 50 0
7.0_0 Tertiary DEI CARBONIFEROUS IPERMIANITRIASSIC I^JURASSIC I CRETACEOUS I TERTIARY^I
Cape Londonderry Oil (in situ)^EnH4 + 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
HYDROCARBON GENERATION PLOT : AGS0/1-SP3400
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
102
TERTIARY^IC 33CRETACEOUS
TIME (Ma)200^150350 300 250 100 50
Iwjky,,,NrwvCape Londonderry
0.0
1.0
Maturity Method : Kinetic
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.
Maturity Method : Kinetic
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
Hyland Bay: Oil Expelled = 0, Gas Expelled = 0 bbl equiv/m2
Tanmurra
Keyling: Oil Expelled = 0, Gas Expelled = 5 bbl equiv/m2
Strat.^Source Rocks
1.0
2.0
7.0
6.0
HYDROCARBON GENERATION PLOT : AGS0/5-SP2800
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
@ AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION
104
1.31.62.02.53.24.0
Maturity Method : Kinetic
Sea Level^—Sediment Interface 8ISO-Ro
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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.
Maturity Method : Kinetic
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^.^I^It^II^I
06.0_
Palaeocene-01 Celle CARBONIFEROUS IP'El4MIANI TRIASS IC I^JURASSIC^CRETACEOUS^TERTIARY
Bathurst Island Oil (in situ)^EIOil (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
HYDROCARBON GENERATION PLOT: AGS0/7-SP1100
105
0 AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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.^I^. •^I.^I
TIME (Ma)200^150
I^i^I
120
100
80 -
60
40
-r
20 Ekl^CARBONIFEROUS I^PERMIAN^I^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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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.
Maturity Method : Kinetic
"
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
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
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
HYDROCARBON GENERATION PLOT: HD16-SP400
1.
1^1^1^ 1^$^•^1^I^I^)^I^,l^ t^ I
^DEI CARBONIFEROUS IPERMIANITRIASSIC I^JURASSIC^( CRETACEOUS I TERTIARY
Hyland Bay: Oil Expelled = 0, Gas Expelled = 0 bbl equiv/m2
CD
Keyling: Oil Expelled = 0, Gas Expelled = 0 bbl equiv/m2
Mid Milligans: Oil Expelled = 19, Gas Expelled = 13 bbl equiv/m2
_ 0.0
_7.0
6.0
_1.0
Oil (in situ)^ElOil (expelled) •Gas (in situ)Gas (expelled)
© AUSTRALIAN GEOLOGICAL SURVEY ORGANISATION ^
110
•••
0.0
1.0
Sea Level^—Sediment Interface •ISO-Ro
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^.^I^.^,^I^,^I^•^t
Present Heatfiow = $4.380 (nYv'V
HEATFLOW AND TECTONIC SUBSIDENCE PLOT: HD16-SP1050
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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
HYDROCARBON GENERATION PLOT: HD16-SP1050
1 1 1
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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
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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.
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Sample #8544:Extracted Rock, Spirit Hill-1, 670-671m, Ningbing Supersequence, ShaleTOC = 0.73%, HI = 123
Frequency factor = 2.8568E +13 s -1
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
Frequency factor = 1.2036E +14 s -1
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.
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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.•
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Sample #8989:Permian Extracted Rock, Kinmore-1, 1470-1473 m, Keyling Supersequence, ShaleTOC = 6.65 %, HI = 283
Frequency factor = 2.7237E +14 s -1
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.
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Sample #7925:Extracted Rock, NEF1002, 208 m, Mililgans Supersequence, Shale^ •TOC = 3.67 %, HI = 292
Frequency factor = 2.1920E +13 s -1
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.
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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).
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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.
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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.
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BURYWWI 1 IKEROGEN (KEYLING.DT2)••••••
64 66
100
80
40
20
0
120Kerogen -> OilOil -> Gas & ResidueKerogen -> Gas
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120
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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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50
40
Kerogen OilOS -> Gas & ResidueKerogen -> Gas
60
20
1 0