MIGRATION, LEAKAGE AND SEEPAGE CHARACTERISTICS OF THE OFFSHORE CANNING BASIN AND NORTHERN CARNARVON BASIN: IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY

2003 ◽  
Vol 43 (2) ◽  
pp. 149 ◽  
Author(s):  
G.W. O’Brien ◽  
R. Cowley ◽  
G. Lawrence ◽  
A.K. Williams ◽  
M. Webster ◽  
...  
Keyword(s):  
Source Rocks ◽  
Large Area ◽  
Potential Field Data ◽  
Canning Basin ◽  
Basin Modelling ◽  
Exploration Risk ◽  
Northern Carnarvon Basin ◽  
Gas Chimneys ◽  
Hydrocarbon Charge ◽  
Carnarvon Basin

RadarSat and ERS Synthetic Aperture Radar (SAR) satellite data have been used for oil slick mapping as part of a systematic interpretative study of the offshore Canning Basin, as well as part of the northern Carnarvon Basin, extending from the inner shelf to the abyssal plain. These seepage data have been integrated with regional geological data, more than 12,000 km of reprocessed Airborne Laser Fluorosensor (ALF) survey data, seismic DHI indicators, water column geochemical sniffer data, potential field data, earthquake data and 2D Petromod basin modelling, to provide new insights into the region’s petroleum prospectivity and key exploration risk factors.From a prospectivity viewpoint, this study has highlighted several areas and processes. Firstly, it is clear that overpressure in the region is principally controlled by the thickness of the Tertiary carbonate wedge and we predict that overpressure may be present in parts of the deeper water Canning Basin. Secondly, the offshore Canning Basin contains a relatively low density of SAR-mapped oil slicks, though this appears to be due to a combination of factors, namely a paucity of vertical conduits for leakage, a predominantly condensate-prone charge and a small slick size.Significantly, several as-yet untested areas emerge from our observations. In the offshore Canning Basin, a 'window' exists in about 1,500–2,500 m of water, where the Triassic source rocks are particularly well placed for liquids generation. Morever, a large area in a radius some 20–80 km outboard of the Bedout High, also appears to have significant untested liquids potential, with respect to sourcing from the Triassic. The shallow section through this region contains a vast area with abundant seismically mapped gas chimneys and other seepage indicators, supporting the conclusions from the remote sensing and basin modelling of significant hydrocarbon charge in this region. Finally, the study indicates that liquids have been generated within the Palaeozoic section of the Bedout Sub-basin.

Petroleum source rocks of Western Australia

2018 ◽  
Vol 58 (1) ◽  
pp. 282 ◽  
Author(s):  
K. Ameed R. Ghori
Keyword(s):  
Western Australia ◽  
Oil And Gas ◽  
Source Rocks ◽  
Lower Permian ◽  
Burial History ◽  
Canning Basin ◽  
Petroleum Systems ◽  
Northern Carnarvon Basin ◽  
Coal Measures ◽  
Carnarvon Basin

Petroleum geochemical analysis of samples from the Canning, Carnarvon, Officer and Perth basins identified several formations with source potential, the: • Triassic Locker Shale and Jurassic Dingo Claystone of the Northern Carnarvon Basin; • Permian Irwin River Coal Measures and Carynginia Formation, Triassic Kockatea Shale and Jurassic Cattamarra Coal Measures of the Perth Basin; • Ordovician Goldwyer and Bongabinni formations, Devonian Gogo Formation and Lower Carboniferous Laurel Formation of the Canning Basin; • Devonian Gneudna Formation of the Gascoyne Platform and the Lower Permian Wooramel and Byro groups of the Merlinleigh Sub-basin of the Southern Carnarvon Basin; and • Neoproterozoic Brown, Hussar, Kanpa and Steptoe formations of the Officer Basin. Burial history and geothermal basin modelling was undertaken using input parameters from geochemical analyses of rock samples, produced oil, organic petrology, apatite fission track analysis (AFTA), heat flows, subsurface temperatures and other exploration data compiled by the Geological Survey of Western Australia (GSWA). Of these basins, the Canning, Carnarvon, and Perth basins are currently producing oil and gas, whereas the Southern Carnarvon and Officer basins have no commercial petroleum discovery yet, but they do have source, reservoir, seal and petroleum shows indicating the presence of petroleum systems. The Carnarvon Basin contains the richest identified petroleum source rocks, followed by the Perth and Canning basins. Production in the Carnarvon Basin is predominantly gas and oil, the Perth Basin is gas-condensate and the Canning Basin is oil dominated, demonstrating the variations in source rock type and maturity across the state. GSWA is continuously adding new data to assess petroleum systems and prospectivity of these and other basins in Western Australia.

DEEPWATER EXPLORATION: NORTH WESTERN AUSTRALIA COMPARED WITH GULF OF MEXICO AND MAURITANIA

2001 ◽  
Vol 41 (1) ◽  
pp. 289 ◽  
Author(s):  
M.R. Bussell ◽  
D. Jablonski ◽  
T. Enman ◽  
M.J. Wilson ◽  
A.N. Bint
Keyword(s):  
Gulf Of Mexico ◽  
Political Stability ◽  
Source Rocks ◽  
Salt Tectonics ◽  
Exploration Risk ◽  
World Class ◽  
Northern Carnarvon Basin ◽  
Oil Expulsion ◽  
Shale Diapirism ◽  
Carnarvon Basin

Some of Australia’s deepwater frontiers are opening up for exploration, with existing and new companies taking acreage positions. Despite favourable fiscal terms and political stability, interest levels have not matched those in international hot spots due to key differences in perceived prospectivity.In this paper, Australia’s deepwater plays in the Northern Carnarvon Basin are compared and contrasted with deepwater plays in the Gulf of Mexico and offshore Mauritania. This comparison is largely based on Woodside Energy Ltd’s exploration pursuits in these areas.The Northern Carnarvon Basin deepwater plays are principally an extension of shallower water petroleum fairways, submerged to greater water depths by the absence of the Tertiary progradational, carbonate shelf sequence. Trap types and reservoir-seal pairs in the deepwater prospects are similar to their shallow water counterparts, but extensive deepwater areas carry an increased exploration risk due to the absence of this shelf overburden to load the Jurassic source rocks into the oil expulsion window. Hydrocarbons generated typically comprise dry gas from deeper Triassic source rocks, often trapped in sub-commercial quantities. Although the basin lacks a world class, widespread, oil-generating source rock, recent deepwater commercial oil discoveries in the Exmouth Sub-basin indicate the existence of a localised sweet spot associated with a Late Jurassic depocentre, similar to the proven Barrow-Dampier Subbasins located in shallower waters.In contrast, Woodside’s deepwater Gulf of Mexico and offshore Mauritania plays combine deepwater depositional systems with present day deepwater. They have reservoir-quality turbidite sandstones, well imaged on excellent quality 3D seismic, sealed by deep marine shales and charged by world class, organic-rich, prolific source rocks. Salt tectonics, shale diapirism and sloperelated slumping and thrusting have generated appealing structural styles, resulting in multiple play types and a density of prospects and leads not seen in Australia’s deepwater frontiers to date.Although elements of these plays are present at some locations in Australia’s deepwater, nowhere yet have all the required exploration ingredients for a major oil province been found juxtaposed as in the proven Gulf of Mexico and the highly prospective offshore Mauritania. Political stability and relatively favourable fiscal terms remain essential in attracting the exploration investment dollar to Australia’s deepwater.

Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data

2011 ◽  
Vol 51 (2) ◽  
pp. 746
Author(s):  
Irina Borissova ◽  
Gabriel Nelson
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Magnetic Data ◽  
Long Distance ◽  
Potential Field Data ◽  
Petroleum Potential ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data ◽  
Insight Into ◽  
Carnarvon Basin

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin. Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics. Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays. Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.

PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 315 ◽  
Author(s):  
K. K. Romine ◽  
J. M. Durrant ◽  
D. L. Cathro ◽  
G. Bernardel
Keyword(s):  
Focal Point ◽  
Source Rocks ◽  
Predictive Tool ◽  
Petroleum Systems ◽  
The North ◽  
Northern Carnarvon Basin ◽  
And Migration ◽  
Play Elements ◽  
Migration Pathways ◽  
Carnarvon Basin

A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.

THE NORTH WEST SHELF

1989 ◽  
Vol 29 (1) ◽  
pp. 529 ◽  
Author(s):  
A.E. Cockbain
Keyword(s):  
Oil Fields ◽  
Gas Field ◽  
North West ◽  
Canning Basin ◽  
The North ◽  
The Indian Ocean ◽  
Northern Carnarvon Basin ◽  
Siliciclastic Sediments ◽  
Breakup Unconformity ◽  
Carnarvon Basin

The region of the North West Shelf dealt with in this paper is underlain by three of the four basins which make up the Westralian Superbasin. The Bonaparte Basin lies outside the scope of this paper; the other basins are the Browse Basin, the offshore Canning Basin, here named the Western Canning Basin, and the offshore Carnarvon Basin, here called the Northern Carnarvon Basin. Sediments belonging to ten depositional sequences (Pz5, Mzl to Mz5, and Czl to Cz4) are present in the basins, the oldest being of Late Carboniferous and Permian age (Pz5).Deposition commenced in rift (interior fracture) basins under fluvial/deltaic conditions in the Late Permian/Early Triassic (Mzl), when the North West Shelf was part of Gondwana. Continental breakup took place in the Middle Jurassic (breakup unconformity between Mz2 and Mz3), and marine conditions prevailed over the Westralian Superbasin thereafter, with deposition taking place in a marginal sag setting. Siliciclastic sediments gave place to carbonates in the Late Cretaceous (Mz5) as the Indian Ocean grew larger.Parts of the area have been under permit since 1946, and to date some 227 exploration wells have been drilled. The most intensive exploration has taken place in the Northern Carnarvon Basin (191 wells), followed by the Browse Basin (20 wells), and Western Canning Basin (16 wells). Thirty- four economic and potentially economic discoveries have been made. The main target reservoirs are Triassic, Jurassic and Cretaceous, and the regional seals are Triassic and Cretaceous. The fields are of two types: pre- breakup unconformity (mainly tilted horst blocks), and post- breakup unconformity (usually four- way dip closures). Of the five producing fields, the North Rankin Gas Field is a pre- breakup field, while the four oil fields (Barrow, Harriet, South Pepper and North Herald) are all post- breakup.

THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA

1993 ◽  
Vol 33 (1) ◽  
pp. 123 ◽  
Author(s):  
B. J. Warris
Keyword(s):  
Western Australia ◽  
Early Carboniferous ◽  
Poor Quality ◽  
Source Rocks ◽  
Structural Development ◽  
Hydrocarbon Migration ◽  
North West ◽  
Canning Basin ◽  
Made In ◽  
Carnarvon Basin

There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.

IDENTIFICATION AND INTERPRETATION OF LEAKING HYDROCARBONS USING SEISMIC DATA:A COMPARATIVE MONTAGE OF EXAMPLES FROM THE MAJOR FIELDS IN AUSTRALIA'S NORTHWEST SHELF AND GIPPSLAND BASIN

2000 ◽  
Vol 40 (1) ◽  
pp. 119 ◽  
Author(s):  
R. Cowley ◽  
G.W. O'Brien
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Hydrocarbon Migration ◽  
North West ◽  
Seal Integrity ◽  
Seismic Amplitudes ◽  
Gas Chimneys ◽  
Hydrocarbon Charge ◽  
Gippsland Basin ◽  
Carnarvon Basin

An extensive volume of 3D seismic data over a number of oil and gas fields in Australia's North West Shelf and Gippsland Basin has been examined for evidence of the effects of hydrocarbon migration and/or leakage. For comparative purposes, 2D and 3D data have also been studied over a number of adjacent traps, including dry traps and partially to completely breached accumulations. Fields and traps investigated include Bayu-Undan, Jabiru, Skua, Swift and Tahbilk in the Bonaparte Basin, Cornea in the Browse Basin, North Rankin, Chinook, Macedon, Enfield and Zeewulf in the Carnarvon Basin, and Kingfish in the Gippsland Basin. The principal goal of the study is to provide representative case studies from known fields so that, in undrilled regions, the exploration uncertainties associated with the issues of hydrocarbon charge and trap integrity might be reduced.Direct indicators of hydrocarbon migration and/or leakage are relatively rare throughout the basins studied, though the discoveries themselves characteristically show seismic anomalies attributable to hydrocarbon leakage. The nature and intensity of these hydrocarbon-related seismic effects do, however, vary dramatically between the fields. Over traps such as Skua, Swift, Tahbilk and Macedon, they are intense, whereas over others, for example Chinook and North Rankin, they are quite subtle. Hydrocarbon-related diagenetic zones (HRDZs), which had been identified previously above the reservoir zones of leaky traps within the Bonaparte Basin, have also been recognised within the Browse, Carnarvon, Otway and Gippsland Basins. HRDZs are the most common leakage indicators found and are identified easily via a combination of high seismic amplitudes through the affected zone, time pull-up and degraded stack response of underlying reflectors. In some cases (the Skua and Macedon Fields), the HRDZs actually define the extent of the accumulations at depth.Anomalous, subtle to strong, seismic amplitude anomalies are associated with the majority of the major fields within the Carnarvon Basin. The strength and location of the anomalies are related to a complex interplay between trap type (in particular four-way dip-closed versus fault dependent), top seal capacity, fault seal integrity, and charge history. In some areas within the Carnarvon, Browse and Bonaparte Basins, shallow amplitude anomalies can be related directly to gas chimneys emanating from the reservoir zone itself. In other instances, the continuous migration of gas from the reservoir has produced an assortment of pockmarks, mounds and amplitude anomalies on the present day sea floor, which all provide evidence of hydrocarbon seepage. In the Browse Basin, strong evidence has been found that many of the modern carbonate banks and reefs in the region were initially located over hydrocarbon seeps on the palaeo-seafloor.The examples and processes presented demonstrate that the analysis of hydrocarbon leakage indicators on seismic data can help to better understand exploration risk and locate subtle hydrocarbon accumulations. In mature exploration provinces, this methodology may lead to the identification of subtle accumulations previously left undetected by more conventional methods. In frontier regions, it can help to identify the presence of a viable petroleum system, typically the principal exploration uncertainty in undrilled regions.

Integration of new interpretation, attribute analysis and inversion results for the Dampier Sub-basin, North West Shelf of Australia

2021 ◽  
Vol 61 (2) ◽  
pp. 611
Author(s):  
Jarrad Grahame ◽  
Jianfeng Yao
Keyword(s):  
Oil And Gas ◽  
New Ventures ◽  
Large Area ◽  
North West ◽  
The North ◽  
Avo Inversion ◽  
Attribute Analysis ◽  
New Interpretation ◽  
Northern Carnarvon Basin ◽  
Carnarvon Basin

The Davros-Typhon Multi-Client 3D surveys are located approximately 70km from the north-west coast of Australia, largely covering the NE trending Dampier Sub-basin and straddling the Rankin Trend within the Northern Carnarvon Basin. The basins within the North West Shelf formed as a result of seafloor spreading, associated with the breakup of the North West margin of East Gondwana. The combined, contiguous Davros-Typhon survey areas cover a number of significant discoveries and producing fields, which include both oil and gas accumulations. The key objective of the survey was to enhance the imaging of Triassic to Lower Cretaceous reservoir units and to develop a new interpretation framework, made possible by the modern broadband acquisition parameters and advanced processing techniques. Challenges associated with imaging and interpretation include the effects of high velocity carbonate overburden, steeply dipping structures, fault shadow and structural complexity at depth, which is critical for evaluation of reservoir targets. A major reprocessing effort was undertaken to further mitigate these issues, which included Davros and a number of adjacent existing 3D surveys, resulting in the Typhon Multi-Client 3D. CGG Multi-client and New Ventures geoscientists, in collaboration with CGG Seismic Imaging, have undertaken new interpretation and amplitude versus offset (AVO) inversion analysis using subsets of the Typhon 3D. The resulting volume-based attribute analysis and integration of new AVO inversion results demonstrates enhanced attribute quality for the reprocessed data and provides a platform for quantitative analysis over a large area of the Northern Carnarvon Basin.

scholarly journals A New Method to Estimate Total Organic Carbon (TOC) Content, an Example from Goldwyer Shale Formation, the Canning Basin

2017 ◽  
Vol 10 (1) ◽  
pp. 118-133 ◽  
Author(s):  
Munther Alshakhs ◽  
Reza Rezaee
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Multiple Regression ◽  
Gamma Ray ◽  
Source Rocks ◽  
Estimation Methods ◽  
Large Area ◽  
Canning Basin ◽  
Sonic Log ◽  
Regression Approach

Background:There is an increasing interest in the Goldwyer Formation of the Canning Basin as a potentially prospective shale play. This Ordovician shaly formation is one of the most prominent source rocks in the Canning Basin. One key property to evaluate the prospectivity of any shale oil or gas is its total organic carbon (TOC) richness.Objectives:This study investigates different TOC estimation techniques and validates the reliability of each, aiming to provide a best estimating approach for local and global applications.Method:The limited well distribution in the large area of the Canning Basin makes a basin-wide study not warranted at this stage. A focused look into the Barbwire Terrace was carried out instead. General TOC estimation methods, such as Schmoker and ∆logR were employed for TOC calculation. TOC relationships of single and multivariate regressions were also derived from wireline data and TOC rock sample measurements.Results:Both Schmoker and ∆logR methods tend to overestimate TOC when compared to the available Rock-Eval pyrolysis TOC measurements. The regression approach have shown to provide the best TOC estiamtes for wells in the Barbwire Terrace, where the best multiple regression approach for the terrace and global application was found to be the one derived from gamma-ray (GR), bulk density (RHOB), and sonic log transit time (DT).Conclusion:The generalized nature of the Schmoker method, as it provides a global relationship between density and TOC is probably the main reason why this approach does not provide a good fit in the case of the Goldwyer Formation. Furthermore, the uncertainty associated with the ∆logR method factors, such as the level of maturity (LOM), and resistivity and sonic baselines greatly influence the TOC estimation in this method, and hence, sometimes do not merit a reliable TOC estimation. The multiple regression approach have shown to be most accurate once lithology and compaction information (GR, RHOB, and DT) were incorporated in the regression process. TOC was reliably estimated for wells inside and outside the Barbwire Terrace, and also for wells of a global lacustrine shale. Such derivation have provided a more accurate technical assessment of the shale play and its prospectivity as a potential unconventional hydrocarbon resource.

Porosity trends and reservoir quality in the Bass Basin

2008 ◽  
Vol 48 (1) ◽  
pp. 227
Author(s):  
Natt Arian ◽  
Peter Tingate ◽  
Richard Hillis
Keyword(s):  
Source Rocks ◽  
Reservoir Quality ◽  
Hydrocarbon Generation ◽  
Relative Lack ◽  
Sonic Log ◽  
Exploration Risk ◽  
Hydrocarbon Charge ◽  
Gippsland Basin ◽  
Sand Bodies

A study of porosity trends and reservoir quality of the Eastern View Group (EVG) of the Bass Basin has been undertaken. Previous exploration in the Bass Basin targeted the Upper EVG due to its stratigraphic equivalence to the hydrocarbon-rich Upper Latrobe Group in the Gippsland Basin. Although this exploration has proved that mature source rocks in the basin have generated and expelled hydrocarbons, the relative lack of hydrocarbon charge into the Upper EVG has previously been identified as a major exploration risk. If hydrocarbon generation is adequate, the lack of Upper EVG accumulations is probably related to limited vertical migration. Thus the reservoir quality of the most relatively charged Middle and Lower EVG is important in determining the basins’ prospectivity. Sonic log data were deemed to be the most appropriate to determine porosity for this study. Wyllie, Clemenceau, Hunt-Raymer and modified Hunt-Raymer equations were used to calculate porosity. The results from each method were compared with available core plug data and the best method (modified Hunt-Raymer) selected. The modified Hunt-Raymer derived porosity trends were examined both vertically and laterally in the basin. In some sandstone intervals an increase in porosity with depth was observed. Thicker sand bodies can exhibit average calculated porosity of approximately 20% even at depths greater than 3,000 m. Several sands in the Middle EVG show a localised increase in porosity with depth, which is attributed to the fining upwards (coarsening downwards) of fluvial channels. The presence of good reservoir sands in the Middle and Lower EVG closer to mature source rocks in the basin is very encouraging as it makes deeper exploration in the Bass Basin more attractive.

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