VMPi

VIICTORIAN NITIATIVE Natural Resources and Environment FMOR INERALS &P ETROLEUM AGRICULTURE

RESOURCES

CONSERVATION

LAND MANAGEMENT

PROSPECTIVITY A ND H YDROCARBON P OTENTIAL O F A REA V01-4 , CDGBENTRAL EEP, IPPSLAND ASIN, VAICTORIA, USTRALIA: 2001 ACREAGE R ELEASE

VIMP REPORT 67

D.WONG, T. BERNECKER

April 2001

0 10 20 30 40 50 PEP155 Km PEP156 LAKES ENTRANCE V00-5 MAFFRA VIC/P41 VIC/P40

SALE 200m LONGFORD

PEP157 1000m V01-4

PEP158 2000m V00-4 3000m

VIC/P36 VIC/P42 VIC/P45 4000m

VIC/P34 V00-3

Acreage under application

AREA OF INTEREST 2001 acreage release VIMP Report 67

Prospectivity and Hydrocarbon Potential of Area V01-4, Central Deep, Gippsland Basin, Victoria, Australia

D. WONG and T. BERNECKER

April 2001

Bibliographic reference: WONG, D. & BERNECKER, T., 2001. Prospectivity and Hydrocarbon Potential of Area V01-4, Central Deep, Gippsland Basin, Victoria, Australia. Victorian Initiative for Minerals and Petroleum Report 67. Department of Natural Resources and Environment.

‹ Crown (State of Victoria) Copyright 2001 Petroleum Development

ISSN 1323 4536 ISBN 0 7306 9456 8 (Hard Copy) ISBN 0 7306 9468 2 (CD-ROM)

This report may be purchased from: Business Centre Minerals & Petroleum Department of Natural Resources and Environment 8th Floor, 240 Victoria Parade East Melbourne, Victoria 3002, Australia

For further technical information contact: Manager Petroleum Development Department of Natural Resources and Environment PO Box 500 East Melbourne, Victoria 3002, Australia Website: www.nre.vic.gov.au/minpet/index.htm

Authorship and Acknowledgments: The report was prepared in the Basin Studies Group, principally by David Wong with contributions by Tom Bernecker. The authors acknowledge the assistance of other DNRE staff: David Moore reviewed an early draft of the report and provided valuable comments. Jim Driscoll provided the initial compilation of some well summaries and well logs. Special thanks go to Eddie Frankel who efficiently drafted and compiled the figures, in particular his endless patience in making amendments and additions on short notice. The report was edited by Mike Woollands and Laiyee Mok prepared the text for publication.

Disclaimer This publication may be of assistance to you but the author and the State of Victoria and its employees do not guarantee that the publication is without flaw of any kind or is wholly appropriate for your particular purposes and therefore disclaims all liability for any error, loss or other consequence which may arise from you relying on any information in this publication.

PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 1

CONTENTS

Executive Summary 3

1Introduction 4 1.1 Location 4 1.2 Results from previous exploration 4 1.3 Well failure assessment 7 Seismic velocity anomalies 7 Fault seal leakage 9 2 Tectonic evolution and stratigraphic framework 12 2.1 Tectonic evolution 12 2.2 Stratigraphy 12 3 Hydrocarbon prospectivity 16 3.1 Source rock maturation and hydrocarbon generation history 16 3.2 Reservoir quality 19 3.3 Structural elements and trap integrity 21 3.4 Identified prospects and leads 21 4 Conclusions 31

References 32

Appendix 1 34 Data Availability 34 List of open file well reports 35 Well summaries of selected wells 37 Formation tops of selected wells 44 Appendix 2 Modelling of the sosurce rock maturation history for the Veilfin 1 well Gippsland Basin Geotrack Report 741 (additional) :CD ROM

Victorian Initiative for Minerals and Petroleum (VIMP) report series 45

List of Table 1 Well status in Area V01-4 7

List of Figures 1 Location map of Area V01-4 5 2 Map showing well locations and seismic grids 6 3 Distribution of mid-Miocene channels 8 4 Distribution of High Velocity Zone in Cod-1 8 5 Thin section photomicrographs from conventional core samples (Cod-1) 8 6 Diagenetic model for channel-fill sediments 10 7 Well log summary of the Latrobe Group interval in Veilfin-1 11 8 Regional structural elements map 13 9 Stratigraphic chart 14 10 Reconstructed thermal and burial history for Veilfin-1 17 11 Variation of VR maturity with time for key stratigraphic units in Veilfin-1 18 2 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

12 "In situ oil" versus time for Type II source rocks derived from the reconstructed thermal history for Veilfin-1 20 13 Well log summary of the Latrobe Group interval in Bream-5. 22 14 Well log summary of the Latrobe Group interval in Conger-1 23 15 Composite seismic section from Bream to Turrum fields 25 16 Geological cross-section from Bream to Turrum fields 26 17 Prospects and leads map 27

18 Seismic section across Veilfin-1, Salmon-1 and Knifejaw prospect 28 19 Seismic section from Veilfin-1 to Snapper field 29 20 Seismic section across Cod-1 and NE Cod lead 30

List of Enclosures 1 Composite seismic section across Bream – Veilfin – Fortescue 2 Montage of Knifejaw Prospect PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 3

This VIMP review indicates that a number of Executive Summary fault-blocks and possible structural traps exist in Area V01-4, but despite its proximity to major oil The offshore Gippsland Basin is a world-class oil- and gas fields, no commercial discoveries were and gas-producing province and Australia’s made. In most cases, well failure is related to premier oil-producing region. Its production problematic depth conversion caused by seismic meets around 40% of the nation’s crude oil and velocity anomalies within the carbonates of the most of the State of Victoria’s gas requirements. Seaspray Group that provide the regional seal to The remaining resources (at P50 level) have been the top-Latrobe hydrocarbon pools. The assessed at 600 MMB liquids and 5 TCF gas, anomalies are produced by a complex much of which is likely to occur in deeper mid-Miocene channel system that has cut deep stratigraphic units. The basin is located into the carbonates and was filled with approximately 200 km east of the city of petrographically diverse sediments. As a Melbourne and is well serviced by roads and consequence, many seemingly valid structures on population centres. A network of pipelines brings seismic lines proved to be artefacts and produced hydrocarbons to the onshore petroleum exploration targets were misinterpreted. As far as processing facilities near Longford (Fig. 1). A gas petroleum systems are concerned, it is interpreted pipeline from these facilities was recently that source, reservoir and seal facies are commissioned to deliver Gippsland gas to Sydney developed within Area V01-4. Lower coastal plain in New South Wales. sediments are recognised source rocks in the basin and these are present in older Latrobe Group Without additional commercially viable sediments. Reservoirs are either represented by discoveries, the offshore Gippsland Basin is facing fluvial channels or by offshore marine sandbodies. a decline in crude oil production over the next Sealing rocks are provided by a variety of 10 years. Compared to other giant international mudstone intervals, both marine and non-marine. hydrocarbon provinces, the Gippsland Basin is The mechanism of fault-seal in the basin, under-explored. However, the potential for however, is still uncertain and more detailed work additional discoveries will ensure continued is needed before clear predictions can be made interest in the region, which will also be whether certain faults act as seals or conduits. maintained by several other factors: Future exploration success in Area V01-4 will • Close proximity to a stable diversified and inevitably hinge on a sound geological and growing economy. geophysical understanding of the Seaspray Group, • The presence of existing infrastructure with now rendered capable through modern processing. potential for third party production into More extensive time-depth conversion based on under-capacity facilities. modern data and technology will help to better • Increased gas market demand in the SE define and delineate closures in depth. In order to Australian region. achieve sufficient velocity data in the gazettal • Deregulation and reform of the upstream and block, new 3D-seismic will be required. downstream gas industry during recent years stimulated increasing access to new interstate gas markets. • An increasingly strong government priority to increase competition in the region.

Area V01-4 is located in the Central Deep of the Gippsland Basin. Covering an area of 740 km2 with water depths ranging from 40 to 75 m, the gazettal block is surrounded by several giant oil and gas fields and has been assessed to offer considerable hydrocarbon potential. This report provides an overview of the acreage and describes the prospects and leads, which exhibit varying risk profiles.

Eight unsuccessful wells were drilled in Area V01-4 between 1965 and 1990, all of which targeted top-Latrobe Group plays. Only Veilfin-1 had oil and gas shows with a production test recovery of 0.3 MMSCF of gas and a small amount of light API condensate over eleven hours of flow from intra-Latrobe sandstones. 4 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

1994). Approximately 90% of the reserves were 1 Introduction discovered at the top of the Latrobe Group (Moore et al., 1992). In April 2001, the Commonwealth of Australia and the State of Victoria Joint Authority will Area V01-4 is still relatively sparsely explored release Area V01-4 for work programme bidding. with only 8 exploration wells drilled in the area The block is located in the centre of the Central during the last four decades from 1965 to 1990 Deep of the Gippsland Basin (Fig. 1). (Fig. 2). Seismic coverage is moderately extensive, but is restricted to 2D surveys, vintages This report provides relevant geological and of which range from the 1960's to 1994. A closely geophysical information with respect to the spaced 2D seismic survey, acquired by Esso/BHPP petroleum potential of the gazetted area. The in 1988, was reprocessed as a 3D equivalent data geological framework and the depositional history set in 1994 by M.I.M. Petroleum Exploration Pty of the sedimentary succession are briefly Ltd (MIMP), the permit holder of VIC/P33 described, while more details regarding seismic between 1992 and 1995. coverage, distribution of known hydrocarbon shows and their geological context are given. A The current understanding of the prospectivity in number of, as yet, untested, prospects and play the area was derived from three exploration concepts are delineated. periods, the first of which dates back to the mid-late 1960's and resulted in the drilling of The assessment relies upon abundant geological Cod-1, the third offshore well in the basin, and geophysical information presented in previous followed by Salmon-1 in 1969. Two more wells, operator’s well completion reports as well as open Swordfish-1 and Rockling-1, were drilled in the file interpretative reports that were submitted to 1970's and the final exploration period in the the Department under the requirements of the 1980's included Veilfin-1, Drummer-1, Conger-1 Petroleum (Submerged Lands) Act. Further and Sawbelly-1 (Table 1 ). details are provided by recent Minerals and Petroleum Victoria (MPV) studies and several All the wells were drilled by Esso/BHPP; no publications by various authors on the additional wells were drilled in the 1990's, but prospectivity of selected areas in the Gippsland MIMP conducted further seismic surveys that led Basin (see section on data availability). to the mapping of a number of prospects and leads. However, because seismic velocity 1.1 Location problems (see below) could not be resolved satisfactorily, MIMP decided to relinquish the Area V01-4 comprises 11 graticular blocks, permit in 1995. In 1996, the area was again covering an area of 740 km2 with water depths gazetted and was awarded as VIC/P39 to a group gradually increasing eastwards from 40 m to headed by Mosaic Petroleum. No new data about 75 m. Surrounded by major oil and gas acquisition was carried out before the permit was fields, such as Bream and Kingfish in the south, surrendered in 2000. Barracouta in the west, Snapper and Marlin in the north and Fortescue and Halibut in the east, the area is appropriately described as Gippsland’s Heartland (Fig. 1). 1.2 Results from previous exploration

Many of the large oil- and gas-accumulations in the basin are hosted by highly permeable shallow marine sandstone reservoirs at the top of the Late Cretaceous to mid-Tertiary Latrobe Group and are sealed by the basin-wide marly carbonates of the Seaspray Group. Simple, yet large, structural traps were readily identified below the prominent top-Latrobe reflector. In later years, some attention was given to Maastrichtian and Palaeocene intra-Latrobe traps, again with considerable success albeit with lower volumes. Exploration has led to the discovery of total reserves exceeding 4 billion barrels of crude/condensate and 9 TCF of gas (Hinton et al., PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 5

200m

4000m

3000m

3000m

38 S 39 S

2000m

1000m

VIC/P41

VIC/ RL3

V00-3

149 E

V00-4

149 E

SOLE

GUMMY

VIC/ P19

BASKER

MANTA

VIC/ RL6

KIPPER

LEATHERJACKET

VIC/ RL2

VIC/ P19

BLACKBACK

VIC/L20

FLOUNDER

VIC/L11

ORBOST

VIC/L9

GRUNTER

ANGLER

VIC/P34

V00-5 PATRICIA

TUNA VIC/ L6

OM

BATFISH

ANGELFISH

AIL

MACKEREL

Pipeline

Proposed

VIC/RL5

HALIBUT

ANEMONE

LONGT

GUDGEON

VIC/L5

VIC/L4

BALEEN

TUNA

WEST

ARCHER

YELLOWT

TURRUM

NORTH

TURRUM

SPERM WHALE

PEP155

COBIA

VIC/ RL4

VIC/ L19

MARLIN

SUNFISH

KINGFISH

VIC/L8

VIC/L7

VIC/P45

FORTESCUE

REMORA

LAKES ENTRANCE

VIC/L3

VIC/L10

148 E

148 E

50

SWEETLIPS

BREAM 'B' V01-4

EMPEROR

A

SNAPPER

MOONFISH

VIC/L14

WHITING

VIC/L2

VIC/L13

BARRACOUT

WIRRAH

VIC/P40

BAIRNSDALE VIC/L18

BREAM

25

Km

VIC/P42

VIC/L1

SEAHORSE

VIC/L16

BEACH

GOLDEN

VIC/ RL1

AY

WHIPTAIL VIC/RL1(V)

0

VIC/ L15

TARWHINE

MULLOW

PERCH

VIC/ L17

DOLPHIN

Tasmania

Proposed

SALE LONGFORD

PEP156

Longford to

VIC/P36

147 E

147 E

PEP157

PEP158

Permit boundary Bathymetry (metres) Gas pipeline Oil & other pipeline Proposed gas pipeline 2001 proposed acreage Gas field Oil field

LEGEND

146 E

PEP131

39 S Figure 1 Location map Area of V01-4 6 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

38 10 S

38 20 S

38 30 S

FL 3

FL 4

148 30 E

TUNA 3

FL 2

ATHENE 1

SELENE 1

PILOTFISH 1A

TUNA 1

1

3

TUKARI 1

BATFISH 1

TREVALLY 1

GUDGEON 1

2

TUNA 2

SMILER 1

ANGELFISH 1

10

2

TUNA 4

FLOUNDER 5

4

MACKEREL

1

FLOUNDER 6

EAST HALIBUT

TRUMPETER 1

FLOUNDER 1

TERAGLIN 1

MACKEREL

1

HALIBUT

ALBACORE 1

AIL 2

AIL 1

km

MORWONG 1 HALIBUT

MACKEREL

148 20 E

COBIA 2

KAHAWAI 1

148 20 E

HERMES 1

AYU 1

YELLOWT

MACKEREL

YELLOWT

MARLIN 4

FORTESCUE 2

TURRUM 4

TURRUM 7

0

COBIA 1

1

TURRUM 3

TURRUM 1

WEST FORTESCUE 1

FORTESCUE 1

K'FISH 5

K6

MARLIN 1

OPAH 1

T2

TAILOR 1

BONITA 1,!A

WRASSE 1 K1

TURRUM 5

FORTESCUE 4

WEST HALIBUT

FORTESCUE 3

DRUMMER 1 THREADFIN 1

K2

ROCKLING 1

EAST K1

148 10 E

148 10 E

ROUNDHEAD 1

MARLIN2

MARLIN 3

TURRUM 6

K3

K4

No SEGY

KINGFISH 9

CONGER 1

K7

SNAPPER 2

SAWBELLY 1

SNAPPER 1

1

SNAPPER 6

SNAPPER 4 SWORDFISH 1

VEILFIN 1

K'FISH 8

NANNYGAI 1

COD 1

148 E

148 E

ORANGE ROUGHY

SNAPPER 5 SALMON 1

SNAPPER 3

GURNARD 1

WHITING 1

SEGY available

EDINA 1

BREAM 5

WHITING 2

WIRRAH 2

WIRRAH 1

WIRRAH 3

147 50 E

147 50 E

BREAM 2

A1

BREAM 3

A4

A2

3D Seismic

LUDERICK 1 OMEO 1

BARRACOUT

OMEO 2A

HARLEQUIN 1

BARRACOUT

TARRA 1

V01-4

A3

BREAM 4A

BARRACOUT

SEAHORSE 1 ds

SEAHORSE 2

147 40 E

147 40 E

A5

BARRACOUT

BARRACOUT

BULLSEYE 1

SPEKE 1

2001 acreage release

W SEAHORSE 1

TARWHINE 1

W SEAHORSE 2

WHIPTAIL 1A

14730E

38 20 S

38 30 S

38 40 S ap showing well locations and seismic gri and seismic well locations ap showing Figure 2 M PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 7

Table 1 Well-status in Area V01-4

Well Year Drilled Operator TD (mKB) Result

Cod-1 1965 Esso 2907.8 Dry hole Salmon-1 1969 Esso 3006.9 Dry hole Swordfish-1 1976 Esso 2468.9 Dry hole Rockling-1 1978 Esso 2684.0 Dry hole Veilfin-1 1984 Esso 3521.0 Gas-show Drummer-1 1985 Esso 2571.0 Dry hole Conger-1 1989 Esso 2971.5 Dry hole Sawbelly-1 1990 Esso 3069.8 Dry hole

1.3 Well failure assessment Zones” (HVZ), which produce distinctive two-way time pull-ups on seismic sections. Exploration in the Central Deep of the Gippsland Recent petrological studies have revealed that Basin is challenged by several factors that commonly contribute to well-failure. Of particular clear differences exist between samples below and within the HVZ (Bernecker & Webb, 1994; Feary relevance to the gazettal block are depth conversion problems and recognition of valid & Loutit, 1998; Holdgate et al., 2000). Below the structures and probably fault seal leakage that HVZ are matrix-dominated clay-rich mudstones and wackestones (marls), commonly represented developed during basin reactivation. In addition, it is evident that the newly identified prospects by fine grained carbonate turbidites (Figs 4 & 5). Within the HVZ the sediments are wackestones- represented by older Latrobe strata are located at depths commonly exceeding 3000 mSS. packstones with a significantly higher percentage of bioclastic debris and therefore higher carbonate content. In addition, the sediments within the Seismic velocity anomalies HVZ are coarser grained, containing fine to medium sand-sized bioclastic fragments, while Under ideal conditions, seismic velocity in a below the HVZ most bioclasts are silt-sized sedimentary sequence increases consistently and (Fig. 5). proportionally with depth. However, it is common to find inversions in the velocity/depth gradients Apart from changes in grain-size and carbonate which may vary laterally, and either create content, the clay-content in the sediments also structural artefacts (seismic “pull-ups”) or move appears to have a strong influence on velocity laterally the position of structures being mapped variations. Ocean Drilling Project (ODP) results on seismic sections. These problems are widely have previously shown that clay-rich marls acknowledged in the Gippsland Basin contain flat, water-filled pores that are oriented (eg. Blackburn, 1986; Maung & Cadman, 1992) parallel to bedding. Because seismic waves travel where dry exploration wells have often been more slowly in water than sediment, the presence drilled over seismic anomalies. of water-filled pores slows waves travelling perpendicular to bedding (Kim et al., 1985). Thus, In most parts of the basin, seismic velocity calcareous claystones are often characterised by anomalies are related to a mid-Miocene channel slower velocities and this can be identified in system (Fig. 3) cut into the Oligocene to Recent sediments below the HVZ, which are marls that carbonate-dominated Seaspray Group, which are only slightly fossiliferous. However, with overlies the reservoirs at the top of the Latrobe increasing depth, compaction will compress and Group. The mid-Miocene channels eroded up to eventually destroy the pores, causing an increase 300 m into a sequence of marly wackestones and in seismic velocity with depth, which is evident calcareous mudstones. The channels are filled from the Seaspray Group. with generally coarser wackestones and packstones, characterised by higher velocities than the underlying carbonates and also show considerable lateral velocity gradients. The concentration of these higher velocity sediments at channel bases and the rapid lateral changes of velocity away from the main channel axes has lead to the development of linear “High Velocity 8 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

100 m

200 m C Co Sa 600 m Sw Sm V R D 2000 m

050 km N

Figure 3 Distribution of mid-Miocene channels PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 9

Post-depositional processes and products have even, moderate bright yellow streaming cut, very also impacted on seismic velocity variations. weak moderate bright yellow green crush cut with Calcite is the dominant cement, but dolomite, 60% light brown to brown oil staining. There glauconite and siderite also occur. In all samples were also minor gas shows below the L. balmei from below the HVZ, ferroan calcite cement is interval down to TD at 3521 mKB. present infilling chambers and cavities within bioclasts, and has strongly overprinted the fine- Drummer-1 was drilled to test the hydrocarbon grained bioclastic debris. By contrast, sediments potential of a stratigraphic trap involving intra- within the HVZ are dominated by non-ferroan or Latrobe shoreface-sandstones being truncated by slightly ferroan calcite (Fig. 5). Coarser-grained sealing marls of the Lakes Entrance Formation. channel sediments contain a higher percentage of The well failed to intersect any intra-Latrobe cement, reflecting greater primary porosities; shoreface facies and a possible seal was breached moreover, these sediments frequently host updip by a top-Latrobe channel. dolomite and glauconite (Bernecker et al., 1998). While it is uncertain how the ferroan/non-ferroan Sawbelly-1 was apparently located in a migration calcite ratio effects velocity variations, it appears shadow while fault seal leakage in Conger-1 is a that the destruction of pore-space by cementation consequence of abundant sands in the younger has an influence and that the lowermost part of sequence being involved in fault reactivation. the channel-fill is preferentially cemented (Fig. 6). Nevertheless, there were hydrocarbon indications below the L. balmei interval at Conger-1. The More detailed studies are required before the sandstones (2776 to 2794.5 mKB) showed traces controls on velocity anomalies in the Seaspray and up to 30% dull yellow-green patchy to Group are fully understood and prediction about occasionally spotty fluorescence. Also identified their variations can be made. It is unfortunate, were a very diffuse faint yellow cut and traces of that only very little core-material is available dull yellow thin residue. Cod-1 and Swordfish-1 from these carbonates. Future explorers need to did not reach the pre-L. balmei (intra-Latrobe consider that definitive petrological analyses can Marker) sequence. reveal the impact of sediment composition on geophysical properties and should include Further details related to well-failure are appropriate sampling in their budgets. contained in MIMP's VIC/P33 Relinquishment Report (MIMP, 1995) and the various well MIMP (1995) carried out a pre-stack depth completion reports (see list at the end of this migration study of the Knifejaw prospect and report). confirmed the difficult task of delineating the structure beneath these high velocity channels. MIMP’s progressive depth conversion techniques decreased the vertical relief of the Knifejaw structure and shifted the crest area, thereby decreasing the structure’s total extent. Whether the calibrated PSDM maps provide an accurate depth map of the structure remains unknown until one or more wells test the prospect. Other alternative velocity modelling techniques have not been tested extensively in this area. Together with petrological analyses, future operators may also want to consider pre-stack or wave equation datum (WED) reprocessing of seismic data or acquiring 3D seismic data to provide better imaging of structures and velocity fields.

Fault seal leakage

Although Conger-1, Sawbelly-1 and Veilfin-1 targeted valid structures, these wells failed probably because of fault seal leakage. Veilfin 1 (Fig. 7) is the only well with oil and gas shows. A production test recovered a cumulative 0.3 MMSCF of gas and a small amount of light API condensate over eleven hours of flow from the 3185 to 3194 mKB interval. The RFT‘s from 3149 to 3213 mKB recovered minor gas with a scum of condensate. Hydrocarbon shows consisted of 60% 10 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Depth COD -1 GR m SN DT MLL

Core 1 1100 bioclastic HVZ III wacke-/packstones 1200

1300 SEASPRAY 1400 Core 2 GROUP 1500 fine-grained II carbonate turbidites

1600

1700 Core 3 hemipelagic 1800 I mudstones Gurnard Fm. 1900 Latrobe Group

Figure 4 Distribution of High Velocity Zone in Cod-1

Figure 5 Thin section photomicrographs from conventional core samples (Cod-1)

Post Channel-Fill Model GR DT

Channel Base High velocity above channel base

Example Log

Figure 6 Diagenetic model for channel-fill sediments PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 11

TD: 3521mKB Veilfin-1 KB: 21m

Depositional Environment NPHI Stratigraphy 0.45V/V -0.15 terrestrial marine GR Depth DT RHOB 0GAPI 200 (m) 140US/F 40 1.95G/C3 2.95 MUDSTONE SEASPR. open Lakes Entrance Fm. (calcareous), GRP. marine, bathyal marl Gurnard Fm. 2000 MUD - sandstone open marine N. asperus

SANDSTONE offshore barrier/ shoreface P. asperopolus 2100

2200

2300 M. diversus

2400

MUDSTONE, lower 2500 COAL, coastal plain

sandstone 2600

L. balmei 2700

58 MA Horizon 2800

LATROBE GROUP 2900

Latrobe Siliciclastics

3000 SANDSTONE, shallow marine mudstone

3100

F. longus lower

coastal plain 3300 MUDSTONE, sandstone, coal

3400

3500

Picks based on palynological analysis by ESSO. Sequence Boundaries based on interpretations by ESSO.

Figure 7 Well log summary of the Latrobe Group interval in Veilfin-1 12 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

association with the uplift and inversion, led to 2 Tectonic evolution and major submarine channelling of the Latrobe stratigraphic framework Group. 2.1 Tectonic evolution 2.2 Stratigraphy

The Gippsland Basin developed in response to the The basic and most widely accepted published break-up of Australia and Antarctica during the stratigraphic framework for the offshore Early Cretaceous and the separation of Australia Gippsland Basin, first presented by James and from the Lord Howe Rise/Campbell Plateau in the Evans (1971), has essentially remained Late Cretaceous (Rahmanian et al., 1990). The unchanged for over 20 years. A wide array of basic basin architecture clearly reflects the stratigraphic names have been used to describe reaction to NNE-SSW directed crustal extension, distinct sedimentary units, many of which are represented by the Northern and Southern laterally discontinuous and irrelevant in terms of Platforms and Terraces, both of which are stratigraphic correlation. More recent industry bounded by complex fault systems (Fig. 8). The work has utilised correlations based on detailed Central Deep hosts the majority of the known biostratigraphic and seismic sequence discoveries and is likely to extend to the stratigraphic studies. Gippsland Rise in the east. The latter is a prominent NE-SW-trending tectonic element and The generalised stratigraphy is summarised in was previously identified on deep seismic and Figure 9. Essentially, the basin-fill can be interpreted as a transform fault system, the Cape subdivided into three groups: Everard Fault system, that defines the eastern basin margin (Megallaa, 1993). Although the • The Strzelecki Group represents early synrift tectonic evolution of the basin is complex, three sedimentation and unconformably overlies major phases can be identified and these are igneous and folded sedimentary rocks of described below: Palaeozoic age. The group is characterised by interbedded lithic and volcanoclastic Early Cretaceous Extension sandstones as well as mudstones and minor coals. The total thickness of the Strzelecki This tectonic phase produced the main rift, Group is poorly defined, but is likely to exceed bounded by the Lake Wellington, Foster and Cape 3000 m. Everard Fault systems (Fig. 8). Non-marine, • volcanoclastic-rich greywackes as well as The Latrobe Group hosts all the known oil mudstones and minor coals of the Strzelecki and gas discoveries in the offshore Gippsland Group filled this initial rift. The maximum extent Basin and is characterised by numerous of these deposits is highlighted in Figure 8. stacked depositional cycles in a range of settings from restricted rift basin to open marine shelf. Deposition was principally Cenomanian-Early Campanian Tasman controlled by rift/drift movements associated Sea Rift with the Tasman Sea opening.

This tectonic phase established the Cape Everard • The Seaspray Group forms the regional seal to Fault System which acted as the major easterly the top-Latrobe hydrocarbon pools in the control on the development of thick rift fill basin. The group is fully marine in the sequences (Latrobe Group) in the subsiding basin offshore and consists of fine-grained (Fig. 9). Rifting ceased by Maastrichtian time and calcareous mudstones, marls as well as the basin continued to deepen due to sediment fossiliferous limestones and represents a loading and thermal subsidence. climate-induced change from siliciclastic to calcareous sedimentation. Early Eocene to Early Miocene Compression The Latrobe Group source, reservoir and seal rocks occur in a variety of stratigraphic units, the During this phase, major anticlines that trap regional correlation of which is often problematic. many of the giant hydrocarbon accumulations A recently completed Ph.D-thesis (Partridge, were generated through inversion of deep grabens 2000) addresses many of these problems and and half-grabens. Simultaneously, the proposes a finer-tuned stratigraphic model for the north-eastern part of the basin was uplifted and basin. The former Golden Beach Group (Lowry & normal faulting produced WNW-ESE striking Longley, 1991) has been subdivided into two fault trends, except where influenced by deeper subgroups (Fig. 9), following the newly proposed structural elements. Sea-level fluctuations, in scheme after Partridge (2000). Partridge concluded from palynological analyses that a PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 13

38 S 38 30 S 39 S

3000 m

200 m

500 m

1000 m 2000 m

3000 m

Graben

Northern

Graben

Southern ipln Rise Gippsland

Max. extent of

Strzelecki Grp.

149 E

149 E

form

Depocentre

Eastern Graben

Terrace

Northern Plat

14830E

Northern

148 30 E

Pisces

Sub-Basin

Terrace

Deep

Kingfish

Max. extent of

Strzelecki Grp.

148 E

Southern

148 E

Deep

Terrace

20

V01-4

form

10 Km

0

147 30 E

147 30 E System

Central

Southern Plat

s

System Fault

aceous extensional

aceous fault System

Terrace

Albian extensional fault systems

Gas field Major anticlinal trends Late Cret Early Cret Early Miocene basin terrace fault systems

Northern Foster

147 E 147 E Fault System

Seaspray

Depression

Fault Lake Fault Wellington s

LEGEND Rosedale Southern

sland Basin Darriman

146 30 E

146 30 E

Proposed 2001 acreage Tertiary - Recent sediment Strzelecki outcrop Palaeozoic granite Palaeozoic outcrop Oil field of the Gipp Figure 8 mapRegional structural elements

38 S 39 S

38 30 S 14 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

TB, 1999

-NE

ting

aceous stratigraphy

Folding

Opening

Opening

Inversion

mainly E-W

Subsidence

Tasman Sea

Tectonics

Late Cret after A. Partridge (in prep.)

Compression

mainly SW

Further Rif

Normal Faulting

Southern Ocean

Reverse Faulting

Divergent Margin

rtclMoment Critical

Accumulation

eeain Migration, Generation,

NILN GROWTH ANTICLINE

rpFormation Trap

FAULTING

vrudnRocks Overburden elRocks Seal

?

v

eevi Rocks Reservoir oreRocks Source

?

a icvr Levels Discovery

Snapper Tuna Barracout Marlin Bream Kingfish Fortescue Flounder Turrum

West Tuna West Tuna Kipper Archer Anemone

Marlin Channel

V

V

.

and

V

OFFSHORE

Channel

Formation

Lakes Entr

Tuna/Flounder

V

V

Mid Miocene Channels

Subgroup

V

Golden Beach

Emperor Subgroup

Latrobe

Siliciclastics

V

V

STRATIGRAPHY

TIGRAPHY

Gurnard Fm.

ONSHORE

V

Gippsland

Limestone (undiff.)

r

o u p

G

t

r

r

a

e a s e

a y

L

o b p

S

l

i

t

r

z

c k

e

e

S

I

. longus

. longus

C

G

D-F

J1-J2

T. lilliei

A1 - A4 B1-B2

H1-H2

C. striatus

P. notensis

T. apoxyexinus

M. diversus

H. uniforma

P. mawsonii

N. senectus

C. paradoxa

P. pannosus

ZONES

P. asperopolus

Lower F

Upper F

Lower L. balmei

Upper L. balmei

Lower N. asperus

Upper N. asperus

F. wonthaggiensis

65 73 83 87 89 91

1.8 5.3

108 115

Ma

54.8 33.7 23.8

97.5

GIPPSLAND BASIN STRA PETROLEUM SYSTEMS ELEMENTS

Albian

Aptian

Coniacian

Turonian

Eocene

Santonian

Miocene

Pliocene

Pleistocene

Oligocene

Barremian

Paleocene

Campanian

AGE

Cenomanian

Maastrichtian

I

T

T

T

E E

E

S Y

C R

R A C

A U R

O Figure 9 Stratigraphic chart PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 15

depositional hiatus, spanning the Coniacian, is By the Early Oligocene, marine conditions were developed across the basin separating the synrift fully established across the Gippsland Basin and Emperor Subgroup from the drift phase Golden carbonate-rich sediments accumulated. The Beach Subgroup (Partridge, 1996). Seaspray Group consists of two formations, which show only subtle lithological differences and are The Emperor Subgroup was deposited in a system generally difficult to separate on wireline logs. of narrow and deep rift-valley lakes developed along Australia’s southern margin during the The lower Lakes Entrance Formation is a early Late Cretaceous (P. mawsonii biozone). The clay-rich calcareous unit that is occasionally overall depositional system included coarse- strongly fossiliferous and forms a regional seal. In grained alluvial fan and fluvial deposits, delivered the central part of the basin, this was deposited in from the uplifted basin margins, as well as outer neritic to upper bathyal conditions. extensive mud-dominated lacustrine sediments (‘Kipper Shale’) in the basin centre. This facies The upper Gippsland Limestone is also clay-rich assemblage has only been penetrated on the and comprises abundant marls. The unit has an Northern Terrace, (eg. Admiral-1, Dart-1, overall higher carbonate content than the Lakes Emperor-1, Hammerhead-1, Judith-1, Kipper 1 & Entrance Formation and contains many 2, Leatherjacket-1, Sole-1, Sweetlips-1, Sunfish-1) fossiliferous packstone horizons (Bernecker et al., and in the modern coastal region at Colliers Hill- 1997). The lower part of the formation is 1, Golden Beach-1A, Golden Beach West-1, characterised by intense channelling that Merriman-1 (Partridge & Macphail, 1997). The produces seismic velocity anomalies. subgroup is not known to host any hydrocarbon accumulations, but oil and gas-shows were identified in sandy intervals within the lacustrine succession in Kipper-1.

After a depositional hiatus from the latest Turonian until the earliest Santonian (Partridge, 1996; Partridge & Macphail, 1997), deposition resumed as a consequence of renewed tectonic activity. These deposits comprise sandstones and shales of the Golden Beach Subgroup reflecting non-marine to open marine environments. The subgroup is mostly confined to the Central Deep and is not known to extend to the north of the Rosedale or south of the Foster Fault Systems. The stratigraphy of the Golden Beach Subgroup is constrained by well control near the modern shelf edge (Archer-1, Anemone-1, Pisces-1, Volador-1, Manta-1, Kipper-1 & 2, Hammerhead-1, Dart-1, Sole-1). A distinct intra-Campanian (80 Ma) unconformity, which is associated with volcanism (Lowry & Longley, 1991), marks the termination of Golden Beach sedimentation.

The third subgroup of the Latrobe Group, the ‘Latrobe Siliciclastics’, is characterised by the strata deposited during a major drift-phase and widening of the basin. The dominant facies regimes are similar to the older Golden Beach Subgroup (Fig. 9), but marine incursions extended progressively across the Central Deep and much further west in retrogradational stacking patterns (Moore, 1997). Coarse-grained, non-marine clastic material, increasingly confined to the basin margins, was transported by rivers towards broad coastal plains and further onto the shelf via deltaic systems. From the Early Eocene onwards, shelf erosion, submarine canyon cutting and channel-fill processes strongly influenced sedimentation in the eastern part of the basin. 16 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Structural integrity is probably the most 3 Hydrocarbon important risk due to the inherent difficulties prospectivity associated with depth conversion, caused by variable velocity mid-Miocene channels with their The presence of large oil and gas fields in the carbonate fills overlying mapped structures, thus Gippsland Basin indicates that a prolific making depth conversion uncertain and creating a petroleum system is active. Although the basin is wide range of possible structural interpretations. considered to be a relatively mature area for MPV has not carried out velocity or depth exploration, estimates of undiscovered resources conversion studies but various publications have indicate that significant oil and gas remains to be recently been published (Bernecker, et al., 1997, discovered (Bishop, 2000). Less explored portions Feary & Loutit, 1998 and Holdgate, et al., 2000) of the basin continue to attract considerable addressing some of these issues. exploration interest because of its world class status. 3.1 Source rock maturation and

Despite a long history of successful search for hydrocarbon generation hydrocarbons, uncertainty still exists with respect history to the type and location of source rocks. Traditionally, the coal-bearing strata of the A burial history and maturation study of the Latrobe Group have been accepted as the main stratigraphic units was carried out by Geotrack source, however, there seems to be disagreement (Duddy, 2000) based on the Veilfin-1 well data about exactly which depositional facies are more and seismic-stratigraphic interpretation. The likely to produce liquid hydrocarbons, rather than report is attached as Appendix 2, while the gas. It appears that the many coaly intervals thermal history and reconstructed burial history within the Latrobe Siliciclastics and the Golden is shown in Figure 10. The variation of maturity Beach Subgroups promote gas generation, due to with time for key stratigraphic units in the the dominance of Type III kerogens. Type I and Veilfin-1 well, based on the thermal history, is Type II kerogens are likely to be mixed with shown in Figure 11. This figure illustrates the Type III kerogens in transitional marine/lower key elements of the predicted source rock coastal plain environments. It is possible that the maturation history at the Veilfin-1 location: organic-rich floodplain deposits of the broad lower coastal plain are prime source rocks for many oil • The upper 500 m of the Strzelecki Group accumulations in the basin. Marine/terrestrial reached a maturation of 0.7 to 0.9% Ro(max) transitions operated throughout the depositional prior to cooling that commenced at ~90 Ma. history of the Golden Beach and Latrobe Active generation recommenced at ~65 Ma, Siliciclastics Subgroups and repeatedly affected reaching 1.5 to 2.0% Ro(max) by ~50 Ma, the extended region around Area V01-4. increasing to ~3.5% Ro(max) at the present- day. The presence of dinoflagellate-bearing horizons demonstrate that marine incursions affected the • The top of the Emperor Subgroup reached a area certainly during F. longus time, and it is also maturation of 0.7 % R (max) at ~50 Ma, likely that marine sediments accumulated as far o west as Veilfin-1 during deposition of the Golden increasing slowly to ~0.9% Ro(max) by Beach Subgroup. It is these marine incursions ~15 Ma and then rapidly increasing to ~1.9% that lead to a preservation of organic matter in Ro(max) at the present-day. coastal plain mudstones. It is therefore concluded that sufficient source rock potential exists in the • The top of the Golden Beach Subgroup area. reached a maturation of 0.5 % Ro(max) at ~30 Ma, increasing slowly to ~0.55% Ro(max) The substantial well database confirms that by ~15 Ma and then rapidly increasing to reservoir and seal facies are present and not ~0.9% R (max) at the present-day. therefore a major risk factor. Offshore marine o sandstones, fluvial and tidal channel sandstones • as seen at Halibut, Cobia and Fortescue fields The top of the Latrobe Siliciclastics remains (Hinton et al., 1994) are likely to be widely immature at the present day, with an distributed in the area. Sealing rocks are Ro(max) of ~0.4 %. provided by a variety of mudstone intervals, both marine and non-marine. The mechanism of fault- seal in the basin, however, is still a matter of contention and more detailed work is needed before clear predictions can be made whether certain faults act as seals or conduits. PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 17

Subgroup

Emperor

Gippsland Lst Lakes Entrance Fm intra-Latrobe Strzelecki Group

Golden Beach Latrobe Siliciclastics

Subgroup

0

P

M

20

O

40

E

P

60

Time (Ma)

80

sland Oil

Reconstruction

K

100

0.9 to 1.1 (%Ro) Initial oil Early Oil Main Gipp Late Oil Gas 0.5 to 0.7 (%Ro) 0.7 to 0.9 (%Ro) 1.1 to 1.3 (%Ro) 1.3 to 2 (%Ro)

Veilfin-1

120

0

1000 2000 3000 4000 5000 6000 7000 8000 et (m) Depth

Subgroup

Emperor

Gippsland Lst Lakes Entrance Fm Gurnard Fm Latrobe Siliciclastics intra-Latrobe Golden Beach Strzelecki Group

Subgroup

0

P

M

20

O

40

E

P

60

Reconstruction

80 Time (Ma)

K

100

Veilfin-1

120

0

50 100 C Temp 150 200 250 300 Figure 10 for Veilfin-1 Reconstructedthermal history and burial 18 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Veilfin-1 Reconstruction

K P E O M P

Gippsland Lst

Lakes Entrance Fm Gurnard Fm 0.5

Latrobe Siliciclastics 0.7

intra-Latrobe 0.9

1.1 1.3 Golden Beach Subgroup

2.0 Initial oil 0.5 to 0.7 (%Ro) Early Oil Emperor 0.7 to 0.9 (%Ro) Subgroup Main Gippsland Oil 0.9 to 1.1 (%Ro) Late Oil Strzelecki Group 1.1 to 1.3 (%Ro) Gas 1.3 to 2 (%Ro) 5.0 120 100 80 60 40 20 0 Time (Ma)

Figure 11 Variation of VR maturity with time for key stratigraphic units in Veilfin-1 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 19

• In terms of active source rock maturation in Thus for an assumed Type II source rock, the range 0.9 to 1.1% Ro(max), generally active oil generation from the main part of considered to be the primary zone for the Golden Beach Subgroup occurred generation of the majority of Gippsland Basin between ~15 and ~4 Ma (within the Miocene). oils, source rocks within the Emperor Subgroup and Golden Beach Subgroup • The Intra-Latrobe unit began rapid generation reached these maturities within the last at ~10 Ma, almost reaching completion at the 20 Ma. present-day.

The generation of "in situ oil" (for an assumed • The Latrobe Group Coarse Clastics began rapid Type II source rock) with time for key generation at ~10 Ma, and reached ~50% stratigraphic horizons in Veilfin-1 is illustrated in completion at the present-day. Figure 12. No significant generation has occurred from units shallower than the Latrobe Group • The upper part of the Strzelecki Group began Coarse Clastics in Veilfin-1 due to oil generation in the mid-Cretaceous and insufficient burial. generated all of its oil potential prior to ~60 Ma (Palaeocene), cracking completely to A fluid history analysis study of six samples from gas by ~50 Ma Veilfin-1 and one sample from Sawbelly-1 was carried out by the Fluids History Analysis (FHA) • The deepest unit of the Emperor Subgroup Group of the CSIRO (Lisk, 1995). The results (EM 3) began oil generation in the mid- were: Cretaceous (~90 Ma) and was totally exhausted at about 60 Ma, cracking • A significant number of quartz grains, with gas completely to gas between 60 and ~30 Ma. and oil inclusions (GOI) ranging from 0 to The middle part of the Emperor Subgroup 2%, were recorded in the analysed samples. (EM 2) began significant generation in the These are consistent with the presence of oil early Tertiary (~65 Ma) and underwent rapid migration under conditions of low saturation generation until completion at about 55 Ma. and comparable in magnitude to samples Cracking to gas took place progressively from taken below the oil water contact in known 55 Ma to completion by ~10 Ma. The upper oilfields. part of the Emperor Subgroup began rapid generation in the early Tertiary (~60 Ma), • Most samples from Veilfin-1 come from the gas reaching effective completion by ~40 Ma, but saturated sands, thus indicating the presence did not begin significant cracking to gas until of an intact seal. The low GOI infers that ~15 Ma. Cracking to gas was completed by there was restricted oil charge, possibly due ~5 Ma. to low permeability or that there was no valid trap at the time of migration. Thus for an assumed Type II source rock, active oil generation from the Emperor • Oil inclusions reflecting derivation from source Subgroup was effectively completed prior to rocks of variable maturities have been 40 Ma (Late Eocene). trapped in the sandstones at Veilfin-1. High maturity oil has been discovered in the • The deepest unit of the Golden Beach inclusions from 3405-3410 m and Subgroup (GB3) began oil generation in the 3370-3375 m. Lower maturity oils were Eocene (~55 Ma) and progressively generated discovered at 3210-3215 m, 3185-3190 m and until completion at ~12 Ma, cracking rapidly, 2030-2035 m. All depths are in mKB. The and completely, to gas by the present-day. single sample from Sawbelly-1 had high The middle part of the Golden Beach maturity oil inclusions. It was suggested Subgroup (GB2) began slow generation in the that the low maturity oil is locally generated Eocene (~50 Ma) and generated ~30% of its and migrated and the higher maturity oils potential by ~15 Ma, at which point it have migrated from a more mature source underwent rapid generation until completion area. at about 8 Ma. Partial cracking to gas took place between 4 Ma and the present-day. • The oil inclusions in all samples occur solely on The upper part of the Golden Beach fractures in detrital quartz and provide no Subgroup began rapid generation in the Late direct constraint to the timing of oil Miocene (~10 Ma), reaching effective migration. completion by ~4 Ma, with only very minor cracking to gas by the present-day. 20 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Veilfin-1 Reconstruction K P E O M P Latrobe Siliciclastics 400 intra-Latrobe

200 "clastics"

0 Golden Beach Subgroup 400 Top Golden Beach Subgroup GB2 GB3

OC) 200

0 Emperor Subgroup 400 Top Emperor Subgrourp EM2 EM3 200

In Situ Oil (mg/g T

Strzelecki Group 400 (upper ~500 m)

200

0 120 100 80 60 40 20 0 Time (Ma)

Figure 12 "In situ oil" versus time for Type II source rocks derived from the reconstructed thermal history for Veilfin-1 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 21

3.2 Reservoir quality 3.3 Structural elements and trap integrity Previous wells in the area were mainly targeted at the top Latrobe Coarse Clastics reservoirs. These Area V01-4 is situated within the western Central reservoirs have been extensively studied Deep and is surrounded by regional high trends throughout the basin and are known to be of hosting the major producing oil and gas fields excellent quality, hosting most of the reserves (Fig. 8). Previous mapping by permit operators discovered to date (Moore et al., 1992). The top showed that the area straddles two deeps, the Latrobe Coarse Clastics have porosity over 20% Western Deep and the Eastern Deep (MIMP, and permeability greater than 5 darcy in the 1995). An anticlinal horst is interpreted to cut Halibut, Cobia and Fortescue fields (Hinton, et al., through the central part of the area on trend from 1994); porosity up to 22% and permeability up to the Bream Field to the Marlin/Turrum fields. 4.8 darcy in Kingfish (Mudge & Curry, 1992); Preliminary regional interpretation by MPV while Cousins (1995) reported an average porosity (Moore and Wong, in prep.) shows that the area is of 22% with permeability up to 10 darcy at the dissected by possible Palaeozoic NNE-SSW Mackerel field. trending faults. These faults could also be reactivated at later tectonism while younger Deeper intra-Latrobe Group reservoirs also form (Golden Beach or younger) NNW-SSE and NW-SE in important reservoir target in the basin. Of the trending faults were formed. These faults created eight wells in V01-4, only Veilfin-1 tested gas, a series of tilted blocks on which Veilfin-1 and within the intra-Latrobe F. longus zone (Fig. 7) other wells drilled previously are located (Encl. 1). while Conger-1 encountered shows in cuttings below the L. balmei zone. At Bream-5, the Lower L. balmei zone consists of a sequence of backswamp and overbank shales and coals with only thin channel sands of fairly limited extent (Fig. 13). It is within this interval that the majority of the intra-Latrobe Group hydrocarbon indications are found. The upper part of this sequence is marked by a significant facies change, with thick massive channel sandstones and only relatively minor coals and shales, being present in the upper L. balmei zone

The Latrobe Siliciclastics at Veilfin-1, in particular between 2116 to 2346 mKB, comprises interbedded fining upward sandstones, shales and coals (Fig. 7), interpreted as point bar units deposited in a coastal plain to flood plain environment. Below this to TD (3521 mKB), the sediments are similar but individual sandstone intervals are much thinner and quite poorly developed. Porosity within the intra-Latrobe was analysed from wireline logs by MIMP to range from 12.3% to 14.5%. The intra-Latrobe at Conger-1 is characterised by upper coastal plain deposits of siltstone, sandstone and coal (Fig. 14).

A review by Hinton et al. (1994) of the Halibut, Cobia and Fortescue core data from the Latrobe Group Coarse Clastics indicates that the major reservoirs at these fields represent braided fluvial facies. Stacked, very coarse to coarse grained, cross-bedded, fining upward, and braided channel deposits were described. Reservoirs of lower porosity (less than 14%) were also interpreted and these were fine to medium grained, lower shoreface deposits or thin, coarse grained, fluvial channel deposits within marsh/lagoonal coastal plain settings. 22 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

TD: 3322 mKB Bream-5 KB: 21m Depositional Environment NPHI Stratigraphy 0.45V/V -0.15 terrestrial marine GR DT RHOB Depth 0GAPI 200 (m) 140US/F 40 1.95G/C3 2.95 SEASPR. GR. Lakes Entrance Fm. Calcareous Marl Open marine, bathyal Glauconitic Mid N. asperus Gurnard Fm. 1900 MUDSTONE, Open marine Lower N. asperus SILTSTONE

P. asperopolus 2000 COAL, SHALE, Deltaic/marginal thin sands Upper M. diversus marine

Mid M. diversus 2100

Lower M. diversus

2200

Upper L. balmei

Massive, thick Deltaic/ 2300 SAND, minor coal channels

2400

Lower L. balmei

SHALE, COAL, Deltaic/shallow thin sand marine

58 MA Horizon 2600

LATROBE GROUP

2700

Latrobe Siliciclastics

2800

2900 Deltaic/marginal SHALE, COAL, marine (Backswamp thin sand and Overbank deposits)

F. longus 3000

3100

3200

3300

Picks based on palynological analysis by ESSO. Sequence Boundaries based on interpretations by ESSO.

Figure 13 Well log summary of the Latrobe Group interval in Bream-5 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 23

TD: 2970mKB Conger 1 KB: 21m

Depositional Environment NPHI Stratigraphy 50 % 1 terrestrial marine GR Depth DT RHOB (m) 0GAPI 200 140 US/F 40 1.95G/C3 2.95 SEASPR. Lakes Entrance Fm. Calcareous Marl Open marine, bathyal GRP. Gurnard Fm. N. asperus Glauconitic Sandstone Open marine Shaley Sands Transition Zone

P. asperopolus

1900 Foreshore/Estuarine SANDSTONES to Lower Coastal Plain (interbeds of silt, sands, (minor offshore coals and shales) component)

Upper 2000 M. diversus

COAL Coastal Plain 51.5 MA Horizon Middle M. diversus 2100

Lower M. diversus 2200

Upper L. balmei

2300

54.5 MA Horizon SILTSTONE, Coastal Plain SANDSTONES, to Shallow COALS Marine 2400

LATROBE GROUP

Latrobe Siliciclastics 2500

Lower L. balmei 2600

58.0 MA Horizon SANDSTONES Coastal (interbeds of siltstones Plain 2700 and coals)

60.0 MA Horizon

2800

67.0 MA Horizon

Upper 2900 F. longus SHALEY Coastal (thin coals) Plain

Picks based on palynological analysis by ESSO. Sequence Boundaries based on interpretations by ESSO.

Figure 14 Well log summary of the Latrobe Group interval in Conger-1 24 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

3.4 Identified prospects and sourced from either the Bream area in the southwest or from the Fortescue area in the east. leads The estimated volume of oil in place is 49 MMBO.

The review by MPV indicates that a number of Spineback fault-blocks and other possible structural traps The Spineback prospect was mapped as a exist in Area V01-4 (Figs 15 & 16). The latest top-Latrobe anticline and as an intra-Latrobe mapping of the area was carried out by MIMP in lowside fault closure, located about 11 km NE of 1994, while BHP Petroleum has also evaluated the Bream A platform. Spineback, like Catfish, is part of their VIC/P1 (South) block that is now also situated directly below a high velocity included in V01-4, and a number of structural channel fill, making depth conversion uncertain. prospects were identified (Fig. 17 & Encl. 1). The reservoirs, seals and source for this structure These prospects are briefly described in the are likely to be similar to those of Catfish following section: (Encl. 1). The estimated volume of oil in place is 33 MMBO. Knifejaw (Untested Swordfish Deep) In their regional mapping, MIMP identified the Hake Knifejaw prospect (untested Swordfish Deep lead). The Hake prospect is also a combined top-Latrobe The structure is mapped as a fault-independent and intra-Latrobe play and lies approximately closure on the downthrown side of the Veilfin 3 km southwest of Spineback. Seismic velocity Fault and was mapped in depth with the crest anomalies associated with channelling in the some 4 km ENE of Veilfin-1. The prospect carbonates are developed here also. It is appears attractive not only because of its large suggested that the reservoir facies is represented size (reserves estimated to be about 50 MMBO), by similar fluvial sandstones as proposed for but also because good reservoir lithologies (with Catfish and Spineback (Encl. 1) and the estimated an average porosity of 15%) are likely to be volume of oil in place is 35 MMBO. The prospect developed in the L. balmei and F. longus may rely on an identical source and similar intervals. The Knifejaw structure would have migration pathways as well. However, because access to oil charged from the Eastern Deep, the bulk of its closure involves intra-Latrobe which is believed to be the source kitchen for the sediments, fault seal is a critical requirement, Fortescue/Mackerel, Kingfish and Halibut fields. increasing the risks. The structure is also situated below the edge of a high relief, high velocity Mid-Miocene channel fill Other leads system that impacts on the accuracy of depth conversion. The montage in Enclosure 2 provides Numerous fault-blocks exist between the the prospect setting and description. Veilfin/Salmon wells and the Fortescue area (Encl. 1) as well as in the northern part of V01-4 Catfish on the Whiting-Conger-Fortescue trend. The Veilfin-Snapper trend (Fig. 19) may also contain The Catfish prospect is located 18 km to the NE of structures with hydrocarbon potential. Previous the Bream A platform. It is a high-side mapping by operators in the area delineated the top-Latrobe and intra-Latrobe closure associated Cod structure and an additional structure to the with a major NW-SE trending fault that is NE of Cod-1 (Fig. 20). These leads require careful transverse to a nose extending NE from the evaluation, especially in the context of velocity Bream Field (Fig. 17 & Encl. 1). High velocity anomalies. Cod-1 was drilled in 1965 to test the Mid-Miocene channel-fill overlies the structure, Top Latrobe play and terminated just above the thus making depth conversion uncertain and Intra-Latrobe Marker where reservoirs of the creating a wide range of possible structural L. balmei and F. longus sequences occur, which interpretations. The anticipated reservoir for this exhibited gas and oil shows in Veilfin-1. prospect is represented by fluvial sandstones that are associated with two separate lowstand/ transgressive systems tracts (P. asperopolus and F. longus) developed in the Latrobe Siliciclastics. Both were encountered in Veilfin-1 (Fig. 7) and Salmon-1, shown by the strong parallel to sub- parallel seismic events at the Intra-Latrobe Marker (lower L. balmei/F. longus) level (Fig. 18).

Top seal is expected to be provided by the Lakes Entrance Formation and cross fault seals for the intra-Latrobe reservoirs are provided by juxtaposed coastal plain mudstones and coals (Figs 15 & 16). It is perceived that this prospect is PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 25 Figure 15 fields to Turrum from Bream Composite section seismic 26 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

0

1

km

10

B’

NE

5

km mudstones (shales)

sandstones, well sorted

cgl.; sand-,silt-, mudstones

conglomerates, sandstones

Turrum-5

sandstones, mudstones, coal

mudstones, sandstones, coal

DOMINANT LITHOLOGIES:

0

al plain

Marlin-2

al/alluvial plain

FACIES REGIME and

deltaic, lower coast alluvial fan submarine channel lacustrine shallow marine, nearshore upper coast

DEPOSITIONAL

Conger-1

Sawbelly-1

Gippsland Limestone Lakes Entrance Fm. undifferentiated

Latrobe Siliciclastics Golden Beach Subgroup Emperor Subgroup

Strzelecki Group:

Seaspray Group:

Latrobe Group:

:

Swordfish-1

Veilfin-1

STRATIGRAPHY

Salmon-1

B’

Turrum-5

Conger-1

Veilfin-1

Marlin-2 Bream-5

Bream-5

Sawbelly-1

Swordfish-1

Salmon-1

B

SW B Figure 16 Geological cross-section from Bream to fieldsTurrum PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 27

3

FL 3

1

FL 4

148 30 E

38 10 S 38 20 S 38 30 S

TUNA ATHENE 1

1

FLOUNDER 2

PILOTFISH 1A

SELENE 1

VIC/L1

TUNA

2

1

TUKARI 1

3

BATFISH 1

4

GUDGEON 1

TREVALLY 1

TUNA

VIC/L6

SMILER 1

2

ANGELFISH 1

FLOUNDER 5

HALIBUT

TUNA

2

FLOUNDER 6

4

MACKEREL

FLOUNDER 1

1

EAST

TRUMPETER 1

TERAGLIN 1

VIC/L5

MACKEREL

1

WAI 1

2

HALIBUT

ALBACORE 1

VIC/L4

AIL 2

MORWONG 1

HALIBUT

MACKEREL

148 20 E

AIL 1

KAHA

148 20 E

COBIA

HERMES 1

1

MACKEREL

AYU 1

YELLOWT

YELLOWT

MARLIN 4

TURRUM 7 FORTESCUE 2

TURRUM 4

COBIA

1

TURRUM 3

TURRUM 1

A 1,!A

FORTESCUE 1

K'FISH 5

K’FISH 6

MARLIN 1 OPAH 1

T2

HALIBUT

TAILOR 1 BONIT

B’

ROUNDHEAD 1

WRASSE 1

K1

TURRUM 5

FORTESCUE 4

WEST

FORTESCUE 3

THREADFIN 1

DRUMMER 1

10

K2

FORTESCUE 1

ROCKLING 1

EAST K1

148 10 E

KINGFISH 9

WEST

148 10 E

MARLIN2

5

km

MARLIN 3

TURRUM 6

K’FISH 3

K’FISH 4

VIC/L7

Y1

0

CONGER 1

K7

SNAPPER 2

C’

VIC/L3

SAWBELL

1

SNAPPER 1

SNAPPER 6

SNAPPER 4 SWORDFISH 1 K'FISH 8

NE Cod

D’

VEILFIN 1

C

NANNYGAI 1

148 00 E

COD 1

148 00 E

Spineback

ORANGE ROUGHY

VIC/L10

SNAPPER 5 SALMON 1

VIC/P45

SNAPPER 3

Hake

D

GURNARD 1

Knifejaw

WHITING 1

Location of seismic lines shown in Figs 13, 16, 18 & 19.

BREAM 5

1

WHITING 2

Cod Deep

Catfish

EDINA

WIRRAH 2

NW Cod

WIRRAH 1

147 50 E

WIRRAH 3

147 50 E

B

BREAM 2

VIC/L14

VIC/L2

BREAM 3

A1

A4

1

A2

LUDERICK 1

OMEO 1

BARRACOUT

HARLEQUIN 1 OMEO 2A

BARRACOUT

TARRA

2001 proposed acreage

BREAM 4A

V01-4

VIC/L19

BARRACOUT

SEAHORSE 1

A3

SEAHORSE 2

147 40 E

147 40 E

VIC/L18

A5

BARRACOUT

VIC/P42

s & leads

BARRACOUT

VIC/L1 SPEKE 1 BULLSEYE 1

AIL 1A

W SEAHORSE 1

Top/Intra Latrobe prospect

W SEAHORSE 2

TARWHINE 1

WHIPT

VIC/L16

VIC/P40

38 40 S

38 20 S 38 30 S

147 30 E Figure 17 leads mapProspects and 28 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

TWT TWT Sec. B (part) Salmon 1 Veilfin 1 Swordfish 1 Sawbelly 1 B’ (part) Sec. 0 0

Gippsland Limestone Formation

1 1

Lakes Entrance Formation

Latrobe Siliciclastics

ntra Latrobe M 2 I arker 2

Golden Beach Subgroup

3 GMIM94a-12 3 02 Km

Figure 18 Seismic section across Veilfin-1, Salmon-1 and Knifejaw prospect PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 29

5 4 3 2 1 0

TWT Sec.

C’

5

km

0

Snapper 2 ld

Swordfish 1

Veilfin 1

Formation

Formation

Latrobe

Subgroup

Group

C

Emperor

Strzelecki

Siliciclastics

Lakes Entrance

Golden Beach

Subgroup

Gippsland Limestone

3 2 1 5 0 4

TWT Sec. eismic section from Veilfin-1 to Snapper fie Figure 19 S 30 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

2 0 3 1

3 0 1 2

TWT Sec.

TWT Sec.

D’

D’

5

5

NE Cod

km

NE Cod

km

0

0

Cod 1

Cod 1 d

Formation

Formation

Latrobe

Subgroup

Formation

Siliciclastics

Lakes Entrance

Golden Beach

Gippsland Limestone

Formation

Latrobe

Subgroup

D

Siliciclastics

Lakes Entrance

Golden Beach

Gippsland Limestone

D

2 0 3 1

TWT Sec. eismic section from Cod-1 and NE Cod lea

2 3 0 1

TWT Sec. Figure 20 S PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 31

4 Conclusions

Despite being surrounded by large oil and gas fields, no commercial discoveries were made in Area V01-4. Of the eight wells in the area, only Veilfin-1 intersected a significant gas-bearing horizon at the intra-Latrobe level. The most recent studies have identified several prospects at intra-Latrobe levels, but none was tested.

The gas-show in Veilfin-1 and the gas and oil inclusion study indicate that a petroleum system exists in the intra-Latrobe, pre-L. balmei intervals. Recent studies by MPV in the deep- water part of the Gippsland Basin clearly outline the importance of the lower Latrobe Group, including the Golden Beach Subgroup as a prospective interval (Bernecker, et al., 2001 and Smith, et al., 2000). The characteristic reservoir/seal facies assemblages of lower coastal plain affinities, as seen on the deep-water seismic, are presumably well developed in V01-4 and encompass both sediments of the Golden Beach and Latrobe Siliciclastics Subgroups.

Exploration in this part of the basin’s Central Deep is challenged by the presence of high velocity channels in the carbonates of the Seaspray Group. A number of research projects have attempted to provide some insights into lithological controls on seismic velocity anomalies. It is generally agreed that lithological variations within the Seaspray Group such as channel-fill versus channel base, changing carbonate contents as well as porosity variations all have a profound impact on seismic velocities.

Future exploration success in V01-4 will invariably hinge on a good geological and geophysical understanding of the Seaspray Group. For obvious reasons, only very limited sample material has been collected to date from that particular stratigraphic unit. It appears imperative that some effort must be spent on accurately describing the carbonates in the area. More extensive seismic velocity analytical techniques and pre-stack reprocessing of the 2D seismic data or acquiring new 3D seismic data will help to better define and delineate closures in depth. 32 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

References HINTON, P.V., COUSINS, M.G. & SYMES, P.E., 1994. BERNECKER, T. & WEBB, J.A., 1994. An The integration of modern technology in investigation of the seismic high velocity zone Gippsland’s central fields study. The APEA within the Seaspray Group, offshore Gippsland Journal, Volume 34, Part 1, pp. 513-852. Basin. Report for MIM Petroleum Exploration JAMES, E.A. & EVANS, P.R., 1971. The Pty Ltd (unpubl.). School of Earth Sciences, La stratigraphy of the offshore Gippsland Basin. Trobe University. The APEA Journal 11, pp. 71–74. BERNECKER, T., PARTRIDGE, A.D. & WEBB, J.A., KIM, D.C., MANGHNANI, M.H. & SCHLANGER, S.O., 1997. Mid-Late Tertiary temperate carbonate 1985. The role of diagenesis in the deposition, offshore Gippsland Basin, development of physical properties of deep-sea southeastern Australia. In: James, N.P. and sediments. Marine Geology, 69, pp. 69-91. Clarke, J. (eds.), Cool Water Carbonates, SEPM Special Publication No. 56, pp. 221-236. LISK, M. 1995. Hydrocarbon migration within sandstones of the Latrobe Group from Veilfin-1 BERNECKER, T., PARTRIDGE, A.D. & WEBB, J.A., and Sawbelly-1, Gippsland Basin. APCRC 1998. Sedimentological perspective on a Confidential Report No. 119 (unpubl.). seismic velocity problem: compositional variations in mid-Miocene channel sediments, LOWRY, D.C. & LONGLEY, I.M., 1991. A new model offshore Gippsland Basin, SE-Australia. or the Mid-Cretaceous structural history of the Geological Society of Australia, Abstracts, northern Gippsland Basin. The APEA No. 49, pp. 28. Journal, Volumne 31, Part 1, pp. 143–153.

BERNECKER, T., WOOLLANDS, M.A., WONG, D., MAUNG, T.U. & CADMAN, S.J., 1992. Seismic MOORE, D.H. & SMITH, M.A., 2001. interpretation problems caused by Miocene Hydrocarbon prospectivity of the deep-water channels in the central part of the Gippsland Gippsland Basin, Victoria, Australia. The Basin: Melbourne, Joint AusIMM (Melbourne APPEA Journal, Volume 41, Part 1, Branch) and PESA (Vic-Tas Branch) ‘Energy, pp. 79-101. Economics and Environment’ Gippsland Basin Symposium, Melbourne, pp. 1–4. BISHOP, M.G., 2000. Petroleum system of the Gippsland Basin. Open-file Report 99-50-Q. MEGALLAA, M. 1993. Tectonic evolution of the US Department of Interior, US Geological Gippsland Basin and hydrocarbon potential of Survey. its lower continental shelf. The APEA Journal, Volume 33, Part 1, pp. 45–61. BLACKBURN, G.J., 1986. Depth conversion: A comparison of methods. Exploration MIM PETROLEUM EXPLORATION PTY LTD, 1995. Geophysics, Volume 17, pp. 67–73. VIC/P33 Relinquishment Report, August 1995, Report No. MIM 152 (unpubl.). COUSINS, M.G., 1995. Geophysical Optimisation of the Mackerel Field Re-development – MOORE, D.H. & WONG, D., (in prep.). Eastern and Gippsland Basin, Australia. The APEA Central Gippsland Basin, Southeastern Journal. Volume 35, Part 1, pp. 79-91. Australia; Basement Interpretation and Basin Links. Victorian Initiative for Minerals and DUDDY, I.R., 2000. Modelling of the source rock Petroleum Report 69, Department of Natural maturation history for Veilfin-1 well, Resources and Environment. Gippsland Basin. Geotrack Report 741 (addition), a report prepared for the Petroleum MOORE, M.A.V., 1997. Integrated play studies – Development Unit, Department of Natural Gippsland Basin. Petroleum Exploration Resources and Environment, Victoria. Society of Australia Ltd., Victoria/Tasmania Branch, 1997 Great Southern Basin FEARY, D.A. AND LOUTIT, T.S., 1998. Cool-water Symposium, Abstracts. carbonate facies patterns and diagenesis – the key to the Gippsland Basin ‘velocity problem’. MOORE, P.S., BURNS, B.J., EMMETT, J.K. & The APPEA Journal, Volume 38, Part 1, GUTHRIE, D.A., 1992. Integrated source, pp. 137-146. maturation and migration analysis, Gippsland Basin. The APEA Journal, Volume 32 Part 1, HOLDGATE, G.R., WALLACE, M.W., DANIELS, J., pp. 313-324. GALLAGHER, S.J., KEENE, J.B. & SMITH, A.J., 2000. Controls on Seaspray Group sonic MUDGE, W.J. & CURRY, J.J., 1992. Development velocities in the Gippsland Basin – a multi- Opportunities in the Kingfish and West disciplinary approach to the canyon seismic Kingfish Fields, Gippsland Basin. The APEA velocity problem. The APPEA Journal, Volume Journal, Volume 32, Part 1, pp. 9-18 40, Part 1, pp. 295–313. PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 33

PARTRIDGE, A.D. 1991. Age limits and environments of deposition of the Golden Beach Group in the Gippsland Basin. Esso Australia Ltd, Palaeontological Report 1991/1.

PARTRIDGE, A. D., 1996. Large break-up lakes of the Bass Strait. Gippsland Basin Symposium 1996, University of Melbourne, Abstracts, pp. 3–6.

PARTRIDGE, A. D. & MACPHAIL, M. K., 1997. New Palynological Analyses from the Latrobe and Golden Beach Groups in Colliers Hill-1, Dutson Downs-1, Golden Beach West-1 and Merriman-1 from Onshore Gippsland Basin. Petroleum Development Unpublished Report 1997/11, Department of Natural Resources and Environment.

PARTRIDGE, A. D., 2000. Late Cretaceous to Tertiary geological evolution of the Gippsland Basin, Victoria. PhD-thesis, La Trobe University, 439, unpublished.

RAHMANIAN, V.D., MOORE, P.S., MUDGE, W.J. & SPRING, D.E., 1990. Sequence stratigraphy and the habitat of hydrocarbons, Gippsland Basin. In J. Brooks (ed.), Classic Petroleum Provinces, Geological Society Special Publication No. 50, pp. 525–541.

SMITH, M.A., BERNECKER, T., LIBERMAN, N., MOORE, D.H. & WONG, D., 2000. Petroleum prospectivity of the deepwater Gazettal Areas V00-3 and V00-4, southeastern Gippsland Basin, Victoria, Australia. Victorian Initiative for Minerals and Petroleum Report 65, Department of Natural Resources and Environment. 34 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Appendix 1

Data Availability

Comprehensive lists of numerous open file exploration data sets and reports on area V01-4 are available from the Minerals and Petroleum Victoria.

Seismic Seismic surveys acquired within or near area V01-4 are listed below.

Seismic Survey Operator Year

Flinders Island-Kingston Marine Seismic Hematite 1963 Gippsland Shelf Marine Seismic Esso 1964 ET-66 Marine Seismic Esso 1966 EC67 Marine Seismic Esso 1967 Gippsland EH-68 Marine Seismic Esso 1968 G69A Marine Seismic Esso 1969 G71A Marine Seismic Esso 1971 G71B Marine Seismic Esso 1971 G72A Marine Seismic Esso 1972 G74A Marine Seismic Esso 1975 G77A Marine Seismic Esso 1978 G80A Marine Seismic Hematite 1980 G81A Marine Seismic Hematite 1981 G82B Marine Seismic Esso 1982 G84A Marine Seismic Esso 1984 GGSI85AD GSI Spec survey GSI 1985 G88A Experimental Marine Seismic Esso 1988 G88AJ 3D Seismic (John Dory) Esso 1988 G92A Marine Seismic-Regional Esso 1992 Protea 1994 Marine Seismic MIM 1994

Wells Well completion reports are available from MPV for wells drilled within and in the vicinity of Area V01-4 (as tabulated on Table 1 in this report) PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 35

List of open file well reports

Data list – Area V01-4

Cod 1

• Well Summary, December 1965, including: Core Analysis Results, October 1965 Palynology Report by Lewis E. Stover, June 1970 The Mid-Tertiary Foraminiferal Sequence by David J. Taylor, November 1965 Biostratigraphic Reappraisal and Facies Study by David Taylor, August 1967 Vitrinite Reflectance Measurements by S. C. Bane, April 1986 FIT Data

Salmon 1

• Well Summary, March 1969, including: Velocity Survey by P. J. Birmingham, February 1969 Palynology Report by Lewis E. Stover, June 1970

Swordfish 1

• Well Completion Report, April 1977 (basic and interpretive data) including: Velocity Survey Formation Interval Tests Record by P. Kemp & D. Moreton, January 1977 Foraminiferal Sequence by David Taylor, February 1977 Palynological Analysis by Alan D. Partridge, May 1977 • Final Well Report (Drilling general data) Rockling 1

• Well Completion Report, April 1979 (basic and interpretive data) including: Palynology Report by H. E. Stacy & A. D. Partridge, March 1979 Quantitative Log Evaluation by H. M. Gordon Velocity Survey by J. Hughes, January 1979

• Geological – Engineering Well Report, January 1979

Veilfin 1

• Well Completion Report, Vol. 1, November 1984 (basic data) including: RFT Results Production Test Results Velocity Survey Report Seismic Calibration Log

• Well Completion Report, Vol. 2, July 1985 (interpretive data) including: Foraminiferal Analysis by J. P. Rexilius, July 1984 Palynological Analysis by M. J. Hannah & M. K. MacPhail, March 1985 Quantitative Log Analysis by L. J. Finlayson, November 1984 RFT Tests Report Geochemical Report by J. K. Emmett, November 1984 Production Test Report

• Well Test Report, April 1984 36 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

• Hydrocarbon Migration within Sandstones of the Latrobe Group from Veilfin-1 and Sawbelly-1, Gippsland Basin Report by M. Lisk, February 1995

• Final Well Report (Drilling general data etc.)

Drummer 1

• Well Completion Report, Vol. 1, July 1986 (basic data) including: RFT Pressure Data Velocity Survey Report by D. Dawson, October 1985

• Well Completion Report, Vol. 2, November 1986 (interpretive data) including: Palynological Analysis by M. K. MacPhail, January 1986 Foraminiferal Analysis by M. J. Hannah, March 1986 Quantitative Log Analysis by J. B. Kulla, December 1985 Wireline Test Report Geochemical Report by T. R. Bostwick, June 1986 Synthetic Seismic Trace

Conger 1

• Well Completion Report, Vol. 1, March 1989 (basic data)

• Well Completion Report, Vol. 2, March 1990 (interpretive data) including: Palynological Analysis by A. D. Partridge, December 1989 Quantitative Log Analysis by A. R. Gilby, June 1989 Geochemical Report by B. J. Burns, February 1990 Synthetic Seismogram

• Palynological Analysis of Conger-1 Gippsland Basin by A. D Partridge, December 1989

• Velocity Survey Report (Sonic Calibration and Geogram Processing Report), March 1989

Sawbelly 1

• Well Completion Report, Vol. 1, April 1990

• Well Completion Report, Vol. 2, June 1990 (interpretive data) including: Palynological Analysis by A. D. Partridge, June 1990 Quantitative Log Analysis by A. R. Gilby, April 1990 Geochemical Report by B. J. Burns, June 1990 Synthetic Trace, June 1990

• Geogram Processing Report (Sonic Calibration Processing and Synthetic Seismogram Processing), March 1990 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 37

Well summaries of selected wells in or near Area V01-4, Central Deep, Gippsland Basin

Well General Notes Stratigraphy Hydrocarbon Potential/Geochemistry Details

Snapper-6 Snapper-6 was drilled to The N-1 reservoir located within The Lakes Entrance Formation and Gurnard test for oil legs downdip Snapper-6 is subdivided into ten Formation act as the seal to the N-1 reservoir. of intra-Latrobe gas mappable units. The top unit is the A gross gas column of 72 m with associated reservoirs discovered by Gurnard Formation and is 42.75 m of net gas sand is intersected at 1353 Snapper-5. Other considered mostly non-net. The mKB (average porosity 25.3%; average water objectives include to other nine units comprise the Coarse saturation 16.4%). An oil leg with 4.25 m of net confirm the lateral Clastics sediments and are oil sand is also intersected over the interval continuity of the intra- described as fluvial-deltaic or 1403.5 to 1410.75 mKB (average porosity Latrobe M and L oil estuarine sandstones. 28.2%; average water saturation 14.8%). The reservoir sands found GOC and OWC lie at 1403.5 mKB and 1410.8 elsewhere in the fault The intra-Latrobe Group consists mKB respectively. An RFT test at 1406.9 mKB block; to test the N-1.1 predominantly of fluvial channel and recovered 21.5 ft3 gas, 5.75 L oil and 21.5 L of and N-1.2 sand quality; point-bar sandstones interbedded water (mud) over 1 minute in a 45.4 L chamber and to confirm the with shales and coals. (choke 1.02 mm, 1888 psia). The oil API at thickness of the N-1.4 oil 15°C was 42.5°. Mudlog shows very high gas leg. readings over the N-1 reservoir interval (approaching 1500 units in some horizons). No significant hydrocarbons were found below the N-1 reservoir, although several minor intra- Latrobe gas reservoirs were penetrated. A gas sand with 4.5 m net sand occurs in the interval 1941.25 to 1948.5 mKB. Between 2390.25 and 2486.25 mKB four sands appear to contain hydrocarbons with high water saturations (68 to 79%). Sidewall cores shot in two of these horizons (2435.2 and 2484.8 mKB) contain gas; they are interpreted as being gas bearing but with high water saturations. These sands are therefore regarded as being water- productive. Gas shows are also inferred in a number of thin sandstones below 2605 mKB. The log analysis shows these thin gas sands as having low average porosity (11.9 to 16.1%) and high average water saturations (25.1 to 79.1%). An interpreted field wide GOC can be inferred due to the juxtaposition of reservoir sandstones across faults which has established fluid communication between fault blocks.

Snapper-2 The well was drilled close The only lithology reports are from A series of hydrocarbon intervals within the N-1 to the highest point of the sections of core cut through the reservoir were recorded (details of which are Snapper structure to test Latrobe Group. Sandstones cored listed below; gross interval of 219.15 m with net the potential of the generally tend to be unconsolidated, gas sand totalling 138.25 m). The GOC and stacked sands beneath medium to coarse grained, hard, OWC are placed at 1392.3 and 1402.1 mKB the intra-M. diversus dolomitic and quartzose. Some respectively. However, very few shows were reflector (Palaeocene sections show good porosity and encountered within the Palaeocene. The report section) in an updip permeability. Mudstone, siltstone proposes this to be as a result of faults position from the shows and coal horizons are also between Snapper-1 and Snapper-2 acting as encountered in Snapper- intersected. barriers rather than migration paths. The 1. Snapper-2 is also in a shows encountered within the Palaeocene different fault block to were either in thin sands, in thick Snapper-1. siltstone/shale sequences, or were too tight to produce. They were also considered to be of very restricted areal extent. 38 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Well General Notes Stratigraphy Hydrocarbon Potential/Geochemistry Details

Snapper-2 The mudlog shows a major increase of (con’t) petroliferous gas from 1188.7 mKB to TD (3051.4 mKB), however this is confused by the presence of numerous coal horizons. The most significant sands lie 1188.7 to 1402.1 mKB (the N-1 reservoir) where high concentrations of propane and butane with trace pentane are recorded. A scum of oil was recovered from 2247 mKB during a FIT; also produced from this was 4 ft3 gas, 18750 cc filtrate and 2300 cc mud. Luderick-1 Luderick-1 was drilled to The Gurnard Formation marks the Two separate accumulations were intersected assess the hydrocarbon top of the Latrobe Group (1777 mKB) by the well. potential of a large intra- and consists of glauconitic offshore Latrobe Group anticlinal marine deposits A 5.5 m oil column with a gas cap is closure northwest of the encountered within the top of the Latrobe Bream Field. The The top of the Coarse Clastics (base Group with the uppermost non-net section structural interpretation of Gurnard Formation) is picked at acting as the seal. The OWC is interpreted at was not significantly 1803 mKB and consists of 1847.5 mKB and the GOC at 1842 mKB. The different to the predrill argillaceous glauconitic siltstones top of the reservoir is taken to be 1832 mKB. ° model, however, it did with thin sand stringers down to 1832 Gas and condensate at 70 API was recovered 3 verify the existence of a mKB (considered to be non-net). by RFT at 1838.5 mKB (124.93 ft gas, 0.78 L small top of Coarse This section is interpreted to have condensate and 0.76 L mud in 13 minutes, Clastics closure. been deposited at the lower 1650 psig, choke size 0.76 mm, 22.7 L shoreface to offshore environment chamber); and oil at 45.9° API at 1843 mKB Closure height increases near storm wave base. Unit 1832 to (6.66 ft3 gas, 0.59 L oil and 21 L water in 15.17 with depth, as does 1844 mKB consists of relatively minutes, 1000 psig, choke size 0.76 mm, 22.7 degree of faulting intensely bioturbated fine to very fine L chamber). Average porosities were 19.9% (although generally less sandstones becoming glauconitic and 19.4% with average water saturations so than at Bream). Whilst towards the top, interpreted to be a 16.8% and 31.5% for the gas and oil zones all large structures are middle to lower shoreface respectively. fault dependent there is environment. Interval 1844 to some degree of fault 1856.5 mKB is described as an An intra-Latrobe reservoir comprises a 2 m independent closure upward coarsening strand plain to sand between 2018 and 2020 mKB, average within deeper levels of upper shoreface facies. This in turn porosity recorded as 24.1% and average water the Latrobe Group. overlies carbonaceous shales and saturation as 20%. A thin shale and coal flaser bedded siltstones 1856.5 to horizon seals the accumulation whilst the base 1860 mKB. This has been is sealed by an 8 m siltstone/shale unit. tentatively interpreted as a tidally Pressure data indicates an OWC at 2009.5 influenced lagoonal facies. mKB. A sample of oil recovered by RFT at 2018 mKB has 61° API (65 ft3 gas, 7922 cc oil On the basis of facies analysis of and 1828 cc water in 13.15 minutes, 1000 psig, core and electrical log analysis, it is choke size 0.76 mm, 22.4 L chamber). proposed that the Gurnard Formation and Coarse Clastics interval Geochemical analysis shows that the oil and represents a transition zone from condensate located within the Coarse Clastics essentially fluviatile sedimentation in is mature and light to medium API belonging to the lowermost section to marine the same oil family as the oil found within the conditions at the top. The sequence intra-Latrobe. 2750 mKB marks the top of represents the onset of the last major organic maturity for significant hydrocarbon marine transgression into the generation; and the Latrobe Group sediments Gippsland Basin. have good hydrocarbon source potential for both oil and gas generation (average TOC of Below 1860 mKB the Latrobe Group 1.33%). is dominated by lower delta plain sediments of amalgamated fining upward sequences of sand-shale- coal point-bar units interspersed with flood plain shales. The point-bar sandstones become more commonly stacked below 1950 mKB although fining upward trends may still be recognised. PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 39

Well General Notes Stratigraphy Hydrocarbon Potential/Geochemistry Details

Salmon-1 Well drilled to test the The Latrobe Delta Formation is No hydrocarbon shows were encountered crest of a closed anticlinal intersected from 2019.3 mKB to TD within the well; gas peaks from the mudlog are feature mapped at the top (3006.9 mKB) and consists of attributed to coal measures within these of the Latrobe Valley interbedded sandstones (quartz, horizons. It is suggested that the well was Formation, expecting to grey to light brown, coarse to very drilled outside closure at the top of the Latrobe find approximately 91.5 m coarse grained up to pebble size, Group. The report concludes that pre-drill of vertical closure. The sub-rounded to rounded, moderately velocity analysis failed to adequately top of the Latrobe Group sorted, some pyrite coating on compensate for the two-way time pull up at the came in 60 m deep to grains, unconsolidated), siltstones top of the Latrobe due to high velocity prediction. Very little (light brown, carbonaceous, sandy, sediments infilling mid-Miocene channels. interpretive work has shaly, pyritic, laminated), shale (light been completed on the to dark brown, silty, carbonaceous, well. weakly pyritic, hard) and coal.

Veilfin-1 Veilfin-1 was drilled to The well intersected 37 m of The Coarse Clastics sands contain no test the hydrocarbon glauconitic greensand at the top of hydrocarbons and are described as being potential of a faulted the Latrobe Group, referred to as the water-wet; this being attributed to the lack of a anticlinal closure. The Gurnard Formation (1988 to 2025 suitable structural trap. top of the Coarse Clastics mKB), before encountering the came in 45 m low to Coarse Clastics between 2025 and On the basis of the quantitative log analysis prediction, thereby 2116 mKB. As no conventional report, a medium to high water saturation gas eliminating any updip cores were cut, wireline log character zone occurs from 3032.25 mKB to TD. potential east of was used to deduce depositional Average porosity and water saturation values Salmon-1. Post-drill environments. The sediments were of these horizons ranged from 10.6 to 14.1% interpretations did interpreted to be stacked and 65.6 to 91.7% respectively (note that SwT however recognise large shoreface/foreshore sandstone units is assumed to be 75% and porosity back stacked fault-dependent displaying typical coarsening upward calculated from Rt between 3250 and 3500 closure within the Latrobe cycles of excellent reservoir quality. mKB). RFT runs were made; however these Group and these migrate A thin 1 m seam of coal encountered were unsuccessful in confirming hydrocarbon to the southeast of between 2042 and 2043 mKB is zones (samples obtained consisted of Veilfin-1 with increasing interpreted as a local back barrier water/filtrate with small amounts of gas and the depth. This could accumulation. pressures recorded could not be interpreted possibly allow for small due to a lack of a constant water gradient line). updip potential within the Within the intra-Latrobe Group, A production test was preformed over the deeper levels of the interval 2116 to 2346 mKB interval 3185–3194 mKB (average porosity Latrobe Group; there is comprises interbedded, relatively 15% and water saturation 45%). 0.3 MCSF of however a corresponding thick sands (10 m), displaying fining gas was recovered over 11 hours at an decrease in porosity with upward character, shales and thick average metered rate of 515 kSCF/d (choke depth. coals (4 m). This is interpreted as size approximately 9.5 mm, initial formation point-bar units deposited in a coastal pressure 4640 psia based on RFT). An plain to flood plain environment. average permeability reading of 0.10 mD was Below this unit to TD (3521 mKB), recorded. An estimated 40 Bbls of formation the sediments are similar to the water and filtrate was also recovered. Pressure preceding interval, comprising of plots nor wireline logs could determine the interbedded sands, shales and coals, GWC. however individual units are much thinner and quite poorly developed. Geochemical analysis shows that the Latrobe Group have very good potential to source gas/condensate and oil (TOC 2.27%). The top of maturation of significant hydrocarbon generation is approximately 2750 mKB.

Conger-1 The well showed no The Coarse Clastics section (top Trace to poor hydrocarbon shows were closure at the top of the taken as 1831 mKB) comprises recorded in the Lower L. balmei and F. longus Coarse Clastics (1831 foreshore and estuarine sands with zones. mKB). However fault interbeds of lower coastal plain silts, dependent closure exists sands and coals and minor thin There is only one interval which intersects within the intra-Latrobe offshore shales This section has appreciable oil fluorescence, horizon 2776 to section. been further subdivided; the top 13 m 2794.5 mKB (up to 30% fluorescence with a referred to as the ‘Transition Beds’ very slow streaming cut and thin ring residue at The lack of hydrocarbons and composed of shaly sands. The 2788 mKB). The log interpretation of this level is attributed to the non-net Upper Sands (1844 to 2025 mKB) suggests the presence of minor residual section being more comprises 181 m of relatively thick hydrocarbons. Three zones within the intra- arenaceous (silty and blocky sands (the majority over 10 m) Latrobe section record a significant increase in coaly) rather than separated by thinner coaly coastal gas over background gas (2585, 2715 and 2770 argillaceous (clay-rich), plain facies. mKB). No producible hydrocarbons are thought 40 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Well General Notes Stratigraphy Hydrocarbon Potential/Geochemistry Details

Conger-1 resulting in a leaky fault Thin coal measures dominate the to be in place as high water saturation is (con’t) gouge. The fault section 2025 to 2055 mKB before the associated with these zones. therefore failed to act as a Top Coastal Plain facies is seal to a significant intersected (2055 to 2610 mKB). This Geochemical analysis of samples indicate the hydrocarbon column. It is interval is characterised by thin coal Latrobe Group has very good potential for proposed that a small horizons (<3m) and fine sands source rock (TOC of a number of samples sub-economic deposited in a less energetic ranged from 1.40% to 8.03%). Further work accumulation may be environment than sections above or shows that the majority of the section present updip of the well below. There are very few reservoir- penetrated is immature (early mature from 2600 location at the deeper quality sandstones within this unit. m to TD), and that the deposits are mostly gas Latrobe levels. Many horizons contain marine prone. The peak generation for significant microplankton assemblages, whilst hydrocarbons would be well below the TD. others with low species diversity are suggested to represent the ephemeral nature of lacustrine and lagoonal environments on the coastal plain that are brackish rather then normal marine in character. Below this interval are thick lower coastal plain sandstones with interbeds of siltstone and coal, referred to as the Lower Sand, before the Bottom Coastal Plain facies is intersected (2879 mKB to TD); a shaly unit with thin coals and no appreciable sands.

Turrum-3 The primary objective The top of the Latrobe Group is A total of 82.25 m of net gas sand and 9 m of was to delineate the L- picked at 1571 mKB and is net oil sand was encountered, most within 1.4.2 oil and gas reservoir dominated by thick channel sands, seven separate ‘L’ accumulations. A further overlying L. balmei coals and shales (Early Eocene, P. three zones of hydrocarbon potential were hydrocarbons. A asperopolus – Lower M. diversus) recognised but not encountered in any previous secondary objective was interpreted to have been deposited in Turrum well (denoted A, B and C reservoirs). to test the Cretaceous a fluvial/estuarine environment. The Details of the reservoir intervals (bar L-1.4.2) section beneath the L shales and coals are interpreted to are shown in the attached table. reservoirs (this objective represent a coastal plain was not met in full as environment with a significant tidal L-1.4.2 is the deepest reservoir, the top being mechanical problems influence. The Upper L. balmei zone at 2586 mKB. It contains a total of 12 m net ° meant wireline logs were (Late Palaeocene) lies in the interval gas sand and 6.5 m net oil sand (38 API). A not run over the interval 1771 to 2055 mKB and consists of sample at 2609.5 mKB recovered 5.25 L of oil 3 2750 to 2995 mKB, shales, coals and minor sands which and 25.2 Ft of gas in a 3.7 L chamber. approximately the are thought to have been deposited Cementation of the reservoir by dolomite Cretaceous interval). in a coastal plain/tidal complex. cement lead to difficulty in delineating the However, mudlog Shales, coals and thick channel reservoir; this also resulted in erroneous results analysis reveals sands once again dominate the given by RFT pressure tests and wireline log hydrocarbons from 2795 Lower L. balmei section. Sands with analysis (for example, OWC prediction lies to 2817 mKB, 2893 to broad lateral extent which have been within a non-net section). Core analysis 2904 mKB and 2929 to deposited in association with relative indicates highly variable permeability within 2934 mKB. The sea-level falls are found with bases these cemented intervals (ranging from 0.234 shallowest intersection at 2696, 2611, 2522, 2353 and 2157 to 394 mD between 2597.36 to 2600.87 mKB probably relates to a mKB. These sands are interpreted at ambient pressure; 0.010 to 312 mD at 31280 gaseous accumulation, to have been deposited in a kPa). GOC was intersected at 2604 mKB and whilst the lower two units fluvial/estuarine environment, with an OWC is predicted at 2615 mKB (from RFT indicate liquid the associated coals and shales pressure data). hydrocarbons. representing a coastal plain/tidal RFT pressure data suggests the 1 m oil environment. The very sandy accumulation directly beneath the L-1.4.2 section at the base of this zone is reservoir (Reservoir ‘C’) is not in due to the amalgamation of sands communication with the main accumulation. from two relative sea-level falls. F. This has important stratigraphic trapping longus zone (2700 mKB to TD) is implications and may have some updip represented by shales, coals and potential. minor sands; once again, it is suggested these sediments were deposited in a coastal plain environment. PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 41

Well General Notes Stratigraphy Hydrocarbon Potential/Geochemistry Details

Turrum-3 Geochemical studies show the Latrobe Group (con’t) sediments have very good potential to source waxy oil, gas and condensate when mature. Studies show the section down to 2350 mKB as being immature, early mature 2350 to 2750 mKB and fully mature 2750 mKB to TD. The paraffinic oils encountered have been sourced from terrestrial organic matter (as per other Gippsland oils).

Drummer-1 The well was drilled to The Coarse Clastics interval is No hydrocarbons were present. The targeted test the potential of a picked at 2434.4 to TD (2571 mKB). shoreface and lower shoreface sands were stratigraphic trap that Consists of basal fluvial channel absent as a result of erosion by a younger P. resulted from the sands overlain by coastal plain asperopolus/Lower N. asperus channel. In truncation of shoreface shales and coals (FM-1.4/M-1.0.2 addition, the lateral equivalents of the basal sands at the 52.5 MY reservoir equivalent). These are seal (FM-1.4/M-1.0.2) had undergone a facies sequence (the sands truncated by a channel which is change to fluvial channel sands. were inferred to have infilled with a tight offshore and lower sub-cropped the Lakes shoreface sequence. This is in turn However, four horizons between 2450.5 and Entrance Formation truncated by the Top-Latrobe 2549.75 mKB show fair to very good porosity ± ± midway between unconformity. (from 16 2% to 22 1%). Canned cuttings gas Rockling-1 and Tailor-1). yields are moderately high 2485-2545 mKB, indicative of fair to good source interval. TOC The failure of this well readings are also fair to good (>1%) for 2448- was largely due to error in 2539 mKB with gas being the expected dip prediction between hydrocarbon (although some scope for minor Rockling-1 and Drummer- condensate/waxy oil potential). Vitrinite 1. There is potential for reflectance indicates the section is still reservoirs lying to the immature down to TD. west of Drummer-1 but these are considered to be very small.

Rockling-1 Rockling-1 was drilled to The Gurnard Formation caps the No hydrocarbons were encountered; all zones test a sand wedge play Latrobe Group (2492 to 2503 mKB) interpreted as water saturated (porosity in the whereby oil could be with the Coarse Clastics interval 2533 to 2635 mKB lie in the range 19.4 trapped by the encompassing in excess of 181 m of to 22.7%; water saturation 87 to 99%). intersection of the top of nearshore marine and alluvial plain the Latrobe Group and an sediments (2503 to 2684 mKB). The intra-Latrobe shale. uppermost marine unit comprises Whilst no hydrocarbons clay-rich, slightly glauconitic and were encountered, pyritic siltstone and fine-grained formation pressure data sandstone. This grades with depth indicates that this type of to more typical sediments of the pinchout play concept still Coarse Clastics, namely interbedded may be valid. sandstone, shale and coal.

West The main Fortescue Field Top-Latrobe is picked at 2421 mKB The FM-1.1 sands encountered within this well Fortescue-1 is a stratigraphic and is represented by approximately were water wet. However, RFT surveys show accumulation where 1 m of Gurnard Formation. The the FM-1.0 as having an oil bearing horizon westerly dipping Coarse Clastics consist of a series of 2431 to 2438 mKB within a relatively good reservoirs at the top of units: quality sand. Log analysis had the OWC at the Latrobe Group are 2438 mKB, however, RFT pressure plots have truncated and sealed by FM-1.0 is the youngest and is the contact as being between 2438 and 2440 the Lakes Entrance truncated by a Middle Eocene to mKB. Pressure data also suggested that the Formation. In addition, Early Oligocene unconformity. FM-1.0 sand is not in direct communication with coals within the FM-1.2 Sediments are 25 m thick and the FM-1.1 and FM-1.2 sands and is therefore reservoir act as an intra- composed of shale siltstone and fine regarded as a separate accumulation. Two formational seal resulting to medium grained sandstone with a samples were retrieved by RFT tests; at 2434 in the development of two clay-silt matrix. Offshore bioturbated mKB 17.6 L 40.5° API oil, 3.96 ft3 gas and 1.75 separate hydraulic siltstone and shales are developed at L filtrate was recovered in a 6 gallon chamber; systems with different the top. The sequence is interpreted at 2436.9 mKB the results were 30.6 L 38.4° OWCs. West Fortescue- to be a lower shoreface to offshore API, 0.53 ft3 and 13.75 L respectively in a 12 1 was drilled to test for marine unit. A sharp boundary gallon chamber. The 7 m of net oil sand 42 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

Well General Notes Stratigraphy Hydrocarbon Potential/Geochemistry Details

West the presence of a separates this unit from the encountered averaged 20% porosity and 43% Fortescue-1 commercially viable oil underlying FM-1.1 unit (thought to be water saturation. The sands encountered (con’t) accumulation in the a sequence boundary). below the OWC are regarded as water bearing. Fortescue FM-1.1 sand west of the Fortescue FM-1.1 is composed of clean blocky This accumulation was assessed to be too Field. The overall dip of sands, medium to very coarse small to support a subsea completion the beds is to the west grained and poorly cemented. The development and so was plugged and although there is a minor sands have a high net-to-gross ratio, abandoned. southerly dip in this area. and are interpreted as an upper shoreface/foreshore deposit. From headspace gas cuttings it is observed that the Latrobe Group sediments are generally FM-1.2 section consists of clean rich in gas from approximately 2450 mKB to blocky sands at its top grading to TD. Wet gas values are generally in excess of interbedded silty sandstones, shales 25% which, together with the total gas levels and coals at its base. This unit observed, indicates the shales and siltstones represents a transition from a within the Group have good oil and gas source shoreface environment at its top to a potential. Average TOC values within the tidal/coastal plain setting at its base. Group are fairly good (average 1.96%), Sands within the unit are thought to however Vitrinite reflectance indicates the represent tidal channels and/or entire section down to TD is presently distributary channels associated with immature. An oil sample from 2437 mKB has interdistributary bay fill sediments an API of 38.5° (the report concludes this has (shales and coal). migrated from deeper in the section). FM-1.3 unit contains a blocky sand at the top (interpreted as a tidal channel) underlain by minor coal, shale and an upward fining sand. This is thought to represent a coastal plain sequence. Coastal plain deposits continue to be deposited from the base of the FM-1.3 to the top of the M-1.2.2 (consist of overbank/floodplain sediments - coals and shales - interfingering with thin sand to silt stringers. The coarser beds represent crevasse splays fanning out into overbank areas during times of maximum stream erosion. This sequence represents an aggradational cycle in coastal plain sedimentation. A sharp boundary at the top of the M-1.2.2 marks a parasequence boundary between coastal plain sedimentation above and offshore marine sedimentation below. During M-1.2.2 time offshore marine sedimentation was interrupted by a rapid relative sea level drop. A progradational/aggradational period of floodplain/coastal plain sedimentation was followed by a marine transgressive phase. Marginal marine conditions prevailed with the later development of upper shoreface to lower shoreface deposits. PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 43

Well General Notes Stratigraphy Hydrocarbon Potential/Geochemistry Details

Halibut-2 Halibut-2 was drilled to The top unit of the Latrobe Group is Reservoir quality sandstones are not present in determine whether there marked by the Turrum Formation the Turrum Formation. However oil saturated were sufficient (2331 mKB), consisting sandstones are intersected within the Flounder incremental reserves to predominantly of sandstone with Formation. The first at 2353.4 to 2359.2 mKB justify additional drilling abundant argillaceous matrix and has a net thickness of 5 m, average effective programs at Halibut. The carbonate and siliceous cement. No porosity of 18% and average effective water objectives include porosity is measured and limonitic saturation of 28%; the second sand from location the current OWC staining is present. The Flounder 2359.6 to 2363.5 mKB has values of 20% and within the Halibut-M171 Formation is intersected at 2351 28% respectively. The lowermost unit lies reservoir and thereby mKB and consists of reworked 2366.7 to 2370.6 mKB and contains 3.7 m of evaluate the presence of Coarse Clastics lithologies with no net sand with porosity at 18% and water lagging oil identified by apparent reduction in reservoir saturation at 24%. The present day OWC is field studies. Also to quality. However, the Flounder taken to be 2370.6 mKB. Pressure analysis confirm the presence of Formation deposits contain minor work shows these hydrocarbon intervals to be the Turrum Formation glauconite (not seen in the Coarse in direct communication with the Coarse (and thereby investigate Clastics), interpreted to have been Clastics reservoirs further down section. The the reservoir potential of deposited by a submarine channel or M-171 reservoir and deeper Halibut reservoirs this unit), provide velocity as a submarine fan. The top of the were encountered, however these had all been and structural control in Coarse Clastics is open to debate; swept (2370.6 to 2425.9 mKB). The effective the region, and finally to being 2391 mKB (based on water saturation of these sands ranges from obtain petrophysical data palynology) or 2394.2 mKB (as per 82% near the current OWC to 96% near the so as to calibrate the Formation Micro Imager analysis). original field OWC. It is proposed that Flounder Halibut Field log analysis. The palynology pick is preferred in Formation sands lie along the truncation edge the end of well report. Three of the Coarse Clastics reservoirs. This allowed flooding surfaces are identified within oil from deeper levels to migrate upwards into the Coarse Clastics; M171 at 2401 shallower levels (the Flounder Formation acting mKB, M181 at 2434 mKB and M191 as a ‘chimney’) leading to these deeper at 2464 mKB. The M171 reservoir is reservoirs being drained. interpreted using Formation Micro Imager (FMI) analysis to be a fining upward braided fluvial unit. From the top of the M181 to 2441 mKB the environment is dominantly fluvial whereas from 2441 mKB to TD the units depositional regime is marine influenced. 44 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

2421.0 2423.0 2419.2 2425.2 2427.5 2671.0

2331.0 2391.0 2326.5 2332.5 2350.0 2560.0 2590.0

2434.5 2451.5 2431.5 2435.0 2441.5 2448.2 2478.8 2493.5 2391.2# 2571.0

2492.0 2503.0 2475.0 2494.0 2495.5 2500.0 2512.0 2609.0 2684.0

2875.0#

2025.0 1831.0 1980.0 1800.01986.0 1479.9 1816.0 2226.1 2057.6 1596.0 3034.5 2858.5 2705.0

3350.0

TION TOPS OF SELECTED WELLS

2019.3 1988.0 1814.0 1571.0 2020.82099.5 2002.62145.8 2030.3 1819.0 2172..0 1860.02228.1 1960.02440.8 1573.5 2399.02688.3 1576.5 2437.1 2110.0 2765.0 2251.0 1660.7 2420.0 1750.5 2061.0 3006.9 3521.0 2970.0 2995.0

FORMA

1777.0 1803.0 1745.0 1777.0 1787.0 1820.0 1919.0 1981.0 2081.7 2270.0 2291.5 2480.0 2995.0 3021.0

1330.5 1349.0 1325.0 1348.0 1516.0 1605.0 1704.0 1787.0 1976.0 2274.0 2998.0 3021.0

1200.3 1230.2 1317.0 1481.9 1673.4 2051.9 2627.4 3051.4

2347.6** 2744.0

Snapper-2* Snapper-6 Luderick-1 Salmon-1* Veilfin-1 Conger-1 Turrum-3 Rockling-1 Drummer-1 Halibut-2 West Fortescue-1

Latrobe Group Coarse Clastics P. tuberculatus Upper N. asperus Middle N. asperus Lower N. asperus P. asperopolus Upper M. diversus Middle M. diversus Lower M. diversus Upper L. balmei Lower L. balmei Upper F. longus Lower F. longus T. lilliei N. senectus Total Depth

All depths in mKB * imperial measurements, converted to metric ** Upper and Lower F. longus grouped under F. longus' # undifferentiated PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 45

15 RYAN, S.M., KNIGHT, L.A. & PARKER, Victorian Initiative for G.J., 1995. The stratigraphy and Minerals and Petroleum structure of the Tyrendarra Embayment, (VIMP) report series Otway Basin, Victoria. 16 KNIGHT, L.A., McDONALD, P.A., Petroleum Reports in bold typeface FRANKEL, E. & MOORE, D.H., 1995. A preliminary appraisal of the pre-Tertiary 1 BUCKLEY, R.W., BUSH, M.D., O’SHEA, P.J., infrabasins beneath the Murray Basin, WHITEHEAD, M. & VANDENBERG, A.H.M., Northwestern Victoria. 1994. The geology and prospectivity of the 17 PERINCEK, D., SIMONS, B.A., Orbost Survey area. PETTIFER, G.R. & GUNATILLAKE, K., 2 VANDENBERG, A.H.M., WILLMAN, C., 1995. Seismic interpretation of the HENDRICKX, M., BUSH, M.D. & onshore Western Otway Basin, Victoria. SANDSTONES, B.C., 1995. The geology and 18 LAVIN, C.J. & NAIM, H.M., 1995. The prospectivity of the 1993 Mount Wellington structure, stratigraphy and petroleum Airborne survey area. potential of the Portland Trough, Otway 3 HOLDGATE, G., 1995. The exploration Basin, Victoria. potential of the Permian Numurkah 19 SIMPSON, C.J., SIMS, J.P. & ORANSKAIA, Trough and Ovens Graben, Victoria. A., 1995. The geology and prospectivity of the 4 BUSH, M.D., CAYLEY, R.A., ROONEY, R., Mt Elizabeth area, Eastern Highlands VIMP SLATER, K. & WHITEHEAD M.L., 1995. The area. geology and prospectivity of the southern 20 ORANSKAIA, A., 1995. A geological margin of the Murray Basin. interpretation of geophysical data over the 5 ROONEY, R., 1995. Mineral exploration Mallacoota 1:250 000 sheet, Eastern history of the North West VIMP area. Highlands VIMP area. NOT RELEASED 6 WILLOCKS, A.J., 1995. An appraisal of the 21 SARMA, S., 1995. Seismic interpreta-tion new airborne surveys over the North West of the offshore Otway Basin, Victoria. VIMP area. 22 MEHIN, K. & LINK, A.G., 1995. Early 7 WHITEHEAD, M.L., 1995. Geological Cretaceous source rocks of the Victorian interpretation of geophysical data over the onshore Otway Basin. Dunolly 1:100 000 sheet. 23 PARKER, G.J., 1995. Early Cretaceous 8 VANDENBERG, A.H.M., CALUZZI, J., stratigraphy along the northern margin WILLOCKS, A.J. & O’SHEA, P.J., 1995. The of the Otway Basin, Victoria. geology and prospectivity of the Mallacoota 24 MOORE, D.H., 1996. A geological 1:250 000 sheet, Eastern Highlands VIMP interpretation of the geophysical data of the area. Horsham 1:250 000 map sheet area. 9 SANDS, B.C., 1995. A geological 25 VANDENBERG, A.H.M., HENDRICKX, M.A., interpretation of the geophysical data from the WILLMAN, C.E., MAGART, A.P.M., Orbost 1994 airborne survey. ORANSKAIA, A.N., ROONEY, S. & WHITE, 10 OPPY, I.D., CAYLEY, R.A. & CALUZZI, J., A.J.R., 1996. The geology and prospectivity of 1995. The geology and prospectivity of the the Orbost 1:100 000 map area, eastern Tallangatta 1:250 000 sheet. Victoria. 11 CALUZZI, J., 1995. Mineral exploration 26 HENDRICKX, M.A., WILLMAN, C.E., history of the Tallangatta 1:250 000 sheet. MAGART, A.P.M., ROONEY, S., VANDENBERG, A.H.M., ORANSKAIA, A. 12 SIMONS, B.A., 1995. An appraisal of new and WHITE, A.J.R. The geology and airborne geophysical data over the prospectivity of the Murrungowar 1:100 000 Tallangatta 1:250 000 map area, Victoria. map area, eastern Victoria. 13 BUSH, M.D., CAYLEY, R.A. & ROONEY, S., 27 BOYLE, R.J., 1996. Mineral exploration 1995. The geology and prospectivity of the history of the Omeo 1:100 000 map area. Glenelg region, North West VIMP area. 28 HAYDON, S.J., 1996. An appraisal of 14 SLATER, K.R., 1995. An appraisal of new airborne geophysical data from the 1995 Omeo airborne geophysical data over the Glenelg survey, Victoria. region, North West VIMP area, Victoria. 29 MAHER, S., 1996. Mineral resources of the Dunolly 1:100 000 map area. 46 PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN

30 CHIUPKA, J.W., 1996. Hydrocarbon Play 46 MAHER, S., VANDENBERG, A.H.M., Fairways of the Onshore Gippsland McDONALD, P.A. & SAPURMAS, P., 1997. Basin, Victoria. The Geology and prospectivity of the 31 MEHIN, K. & LINK, A.G., 1996. Early Wangaratta 1:250 000 map sheet area. Cretaceous source rock evaluation for oil 47 ORANSKAIA, A.N., 1997. Geological and gas exploration, Victorian Otway interpretation of geophysical features Bendoc Basin. 1:100 000 sheet. 32 SLATER, K.R., 1996. An appraisal of new 48 ORANSKAIA, A.N., 1997. Geological airborne geophysical data over the Dargo interpretation of geophysical features Cann, region, Victoria. Mallacoota and Victorian part of Eden 1:100 33 McDONALD, P.A., 1996. An appraisal of new 000 sheets. airborne geophysical data over the Corryong region, northeastern Victoria. 49 WILKIE, J.R. & BROOKES, D.J., 1997. Mineral exploration history of the Wangaratta 34 TWYFORD, R., 1996. An appraisal of 1:250 000 map area. airborne geophysical data from the Murrindal survey, Victoria. 50 McDONALD, P.A., 1997. An appraisal of airborne geophysical data from the Yea 35 HUTCHINSON, D.F., 1996. Mineral survey, Victoria. exploration history of the Dunolly 1:100 000 map area. 51 EDWARDS, J.E., WILLMAN, C.E., McHAFFIE, I.W., OLSHINA, A. & 36 BROOKES, D.J. & BOYLE, R.J., 1996. WILLOCKS, A.J., 1997. The geology and Mineral exploration history of the Bairnsdale prospectivity of the Castlemaine, Woodend, 1:250 000 map area. Yea and part of Bacchus Marsh 1:100 000 map 37 MAHER, S., HENDRICKX, M.A., BOYLE, sheets. R.J. & BROOKES, D.J., 1996. Geology and prospectivity of the Bairnsdale 1:250 000 map 52 MAHER, S., MOORE, D.H., CRAWFORD, sheet area. A.J., TWYFORD, R. & FANNING, F.M., 1997. Test drilling on the southern margin of the 38 McDONALD, P.A. & WHITEHEAD M.L., Murray Basin. 1996. Geological interpretation of geophysical data over the Ararat 1:100 000 map sheet. 53 LAVIN, C.J. & MUSCATELLO, T. 1998. The Casterton Group - Otway Basin 39 MOORE D.H., 1996. A geological Victoria. NOT RELEASED. interpretation of the geophysical data of the Ouyen 1:250 000 map sheet area. 54 MEHIN, K. & BOCK, M.P., 1998. 40 BROOKES, D.J., 1996. Mineral exploration Cretaceous source rocks of the onshore history, Ararat and Grampians 1:100 000 map Gippsland Basin, Victoria. areas. 55 GEARY, G. & REID, I., 1998. Geology and 41 LAVIN, C.J., & MUSCATELLO, T., 1997. prospectivity of the offshore eastern The petroleum prospectivity of the Otway Basin, Victoria, for the 1998 Casterton Petroleum System in the Acreage Release. Victorian Onshore Otway Basin. 56 MEGALLAA, M., BERNECKER, T. & 42 CHIUPKA, J.W., MEGALLAA, M., FRANKEL, E., 1998. Hydrocarbon JONASSON, K.E. & FRANKEL E., 1997. prospectivity of the Northern Terrace, Hydrocarbon plays and play fairways of offshore Gippsland basin, for the 1998 four vacant offshore Gippsland Basin Acreage Release. areas, 1997 acreage release. 57 LAVIN, C., 1998. Geology and 43 MEHIN, K. & LINK, A.G., 1997. Late prospectivity of the western Victorian Cretaceous source rocks offshore Otway Voluta Trough - Otway Basin, for the Basin, Victoria and South Australia. 1998 Acreage Release. 44 WILLOCKS, A.J., 1997. An appraisal of 58 EDWARDS, J., SLATER, K.R. & PARENZAN, airborne geophysical data from the M.A., 1998. Bendigo and part of Mitiamo Castlemaine-Woodend survey, Victoria. 1:100 000 map area geological report. 45 HUTCHINSON, D.F., 1997. Mineral 59 RADOJKOVIC, A., 1998. Mineral exploration exploration history of the Heathcote and history of the Ballarat and Creswick 1:100 000 Nagambie 1:100 000 map areas. map areas. PROSPECTIVITY OF CENTRAL DEEP, GIPPSLAND BASIN 47

60 MESSENT, B.E., COLLINS, G.I.C. & WEST, B.G., 1999. Hydrocarbon prospectivity of the offshore Torquay Subbasin; Victoria: Gazettal AreaV99-1. 61 SMITH, M.A., 1999. Petroleum systems, play fairways and prospectivity of the Gazettal area V99-2, offshore southern Gippsland Basin, Victoria. 62 MEHIN, K., & CONSTANTINE, A.E., 1999. Hydrocarbon potential of the western onshore Otway Basin in Victoria, 1999 acreage release. 63 HUTCHINSON, D.F., 1999. Mineral exploration history of the Castlemaine, Woodend, Yea and part of Bacchus Marsh 1:100 000 map areas. 64 BATSON, R.A., 1999. Mineral exploration history of the Warburton 1:250 000 map area. 65 SMITH, M.A., BERNECKER, T., LIBERMAN, N., MOORE, D.H. & WONG, D., 2000. Petroleum prospectivity of the deep-water gazettal areas V00-3 and V00- 4, southeastern Gippsland Basin, Victoria, Australia. 66 CONSTANTINE, A.E., 2000. Petroleum systems, play fairways and prospectivity of the Gazettal areas V00-1 and V00-2, offshore Otway Basin, Victoria. 67 WONG, D. & BERNECKER, T., 2001. Prospectivity and Hydrocarbon Potential of Area V01-4, Central Deep, Gippsland Basin, Victoria, Australia. 2001 Acreage Release. 68 CONSTANTINE, A.E., GEARY, G.C. & REID, I.S.A., 2001. Hydrocarbon Prospectivity of Areas V01-1 to V01-3, Offshore Western Otway Basin, Victoria, Australia, 2001 Acreage Release. 69 MOORE, D.H. & WONG, D., 2001. Eastern and Central Gippsland Basin, Southeastern Australia, Basement Interpretation and Basin Links. (In Prep) 70 CONSTANTINE, A.E. & LIBERMAN, N., 2001. Hydrocarbon Prospectivity Package, Eastern Onshore Otway Basin VIC/O-01(1), VIC/O-01(2) and VIC/O-01(3), 2001 Acreage Release. MPVINERALS AND ETROLEUM ICTORIA P.O.BOX 500 EMAST ELBOURNE VIC. 3002 250VP VICTORIA P ARADE EMAST ELBOURNE VIC. 3002 P03PHONE: 039412 5084 F03FAX: 039412 5156