bluuebunny/crossref_metadata_2025 huggingface dataset:
HALF-GRABEN MODEL FOR THE STRUCTURAL EVOLUTION OF THE FITZROY TROUGH, CANNING BASIN, AND IMPLICATIONS FOR RESOURCE EXPLORATION
Authors: Drummond B.J. , Etheridge M.A. , Davies P.J. , Middleton M.F.
Published: August 2017

The Fitzroy Trough is a north-west/south-east trending rift along the north-east margin of the Canning Basin. The major crustal extension in the trough occurred in the Middle Devonian to Early Carboniferous. Most idealised cross-sections show down-to-trough normal faults bounding both sides of the trough. In contrast, we show the trough to have a half- graben style, with one side a hinge zone or flexure, and the other side bounded by normal faults. Thus, the basin has marked structural asymmetry. The sense of asymmetry switches several times along strike with the hinged margin on the north-eastern margin in some places and the south-west margin in others. The switching in asymmetry occurs at transfer faults. This structural style is expected in extensional tectonic models where the extension occurs on a detachment surface and is typical of many continental and passive margin rifts. The asymmetry of the Palaeozoic structure has implications for resource exploration because of its influence on facies development in and subsequent structural evolution of the trough. Quite different syn-rift clastic and carbonate facies are expected on faulted and hinged margins of a half-graben. Post-rift subsidence will also be somewhat asymmetric, influencing the carbonate reef geometry in particular. Mesozoic deformation in the basin reactivated many of the Palaeozoic normal and transfer faults, and induced reverse slip up basement surfaces on the hinged margin segments.
SEISMIC AMPLITUDE ANALYSIS: AN END TO FIELD APPRAISAL?
Authors: Tilbury Larry A. , Smith Philip M.
Published: August 2017

The success of lateral prediction techniques based on seismic reflection amplitude analysis has had a significant impact upon recent appraisal and development planning strategies in the Coodwyn Gas Field, offshore north-western Australia.The Coodwyn structure is one of a series of major tilted fault blocks on the Rankin Trend. The gently dipping reservoir sequence of Late Triassic to earliest Jurassic age is truncated by a major erosional unconformity and is overlain by sealing Cretaceous sediments. It is situated some SO kilometres west- south-west of the producing North Rankin Gas Field, to which it bears a striking resemblance in structural form and reservoir stratigraphy. Eight appraisal wells have been drilled in and around the field since its discovery in 1971. The most recent appraisal drilling campaign was designed to test a possible northern extension of the field within a stratigraphically younger reservoir sequence than that previously seen. The success of this campaign was such that the northern Coodwyn reservoirs are now being evaluated as possible candidates for development from a Coodwyn Platform to provide gas for the North West Shelf Project - one of the largest and most ambitious natural resource developments yet undertaken in Australia.During the latest campaign it was confirmed that seismic reflection amplitudes at the Main Unconformity were directly related to the lithology and fluid content of the subcropping reservoir sequence. This has allowed the gas-bearing sands to be mapped across the field with far greater confidence than was previously possible, obviating the need for further appraisal drilling. In fact, Coodwyn -10, a well proposed to intersect the unappraised upper F sands, was not drilled because of the confidence placed in the amplitude map.The amplitude map was used extensively during the 1986 drilling campaign, for refining the structural interpretation of the field, and during the recent Goodwyn Field development planning for the targeting of notional development wells from possible platform locations.
THE PETROLEUM POTENTIAL OF THE GUNNED AH BASIN AND OVERLYING SURAT BASIN SEQUENCE, NEW SOUTH WALES
Authors: Hamilton D.S. , Newton C.B. , Smyth M. , Gilbert T.D. , Russell N. , McMinn A. , Etheridge L. T.
Published: August 2017

The Permo-Triassic Gunnedah Basin has good potential for the discovery of commercial petroleum. Gas shows have been reported from the Porcupine-Watermark, Black Jack and Digby Formations, and from the basal sandstone of the Purlawaugh Formation in the overlying Surat Basin sequence. Gas flowed on drill stem test from the Porcupine-Watermark Formation in the Wilga Park No. 1 discovery well although the find was sub-commercial. An oil show was observed in Lower Permian volcanics, and oil staining has been observed in the Pilliga Sandstone in several wells. The origin of oil staining in the Pilliga Sandstone is unknown, however, and may have been the result of diesel contamination during drilling operations.Structural style within the basin sequence is characterised by north-south and north-north-west/south- south-east trending anticlines which formed in response to periodic compressive and left lateral strike-slip movements along the main Hunter Mooki Thrust Fault. These anticlines are attractive exploration targets.Westerly-derived quartz-rich sandstones occur at several stratigraphic levels within the Black Jack Formation and within the upper Digby Formation. Sandstones of the western bed-load fluvial system (lower Black Jack Formation) are most prospective with thick sections (up to 8 m) giving permeabilities from several hundred to several thousand millidarcies. Marine reworked easterly-derived sandstones up to 12 m thick in the Black Jack and Watermark Formations have minor reservoir potential with permeabilities in the order of tens of millidarcies. All potential reservoirs within the sequence are considered to be adequately sealed. Regionally extensive shaly units deposited either by marine incursion or lacustrine inundation overlie most reservoir horizons; remaining reservoirs are capped by intraformational shales.Organic petrology and geochemistry indicate the best potential source rocks within the Gunnedah Basin are floodplain, lacustrine and shallow marine facies of the Purlawaugh, Napperby, Watermark, Maules Creek and Goonbri Formations. The shallow marine Arkarula Sandstone Member within the Black Jack Formation also has significant potential for oil generation. Vitrinite reflectance, liptinite auto-fluorescence and TAI values indicate Lower Permian sediments are marginally mature to mature for oil generation. Combining the data on source quality and quantity with thermal maturity, the Permian sediments - in particular the Watermark Formation - have the best potential for generating oil.
ACCESS TO LAND FOR EXPLORATION — THE ADOPTION OF MULTIPLE LAND USE PRINCIPLES IN SOUTH AUSTRALIA
Authors: Morozow O.
Published: August 2017

The continued access to land for exploration by the petroleum and mineral industries in Australia has been increasingly impeded by State and Commonwealth legislation aimed at dedicating Crown Land for single land uses.In September 1986, South Australia's Minister for Mines and Energy, Ron Payne, announced a Cabinet decision for 'a package of recommendations designed to foster multiple land-use concepts and to ensure that no land is alienated from exploration without careful consideration of the sub-surface mineral/petroleum potential, relevant economic factors and the existing and potential sub-surface rights'.In this one innovative and potentially far-reaching move, the South Australian Government has:provided a framework to reconcile conflicting interests;indicated a willingness to listen and act upon the expressed legitimate concerns of industries of vital economic importance to the State;made it necessary for the proponents of reserve areas such as National Parks to be more accountable and to provide balanced, scientific substantiation;indicated its intention to make legislative changes to allow for the adoption of multiple land-use principles; andredressed the imbalance where, in the words of the Minister, 'Legislation providing for Aboriginal land rights, the creation of national and conservation parks, and State Government heritage areas have, to varying degrees, created unforeseen consequences for the resources industry'.The first practical test of this new Government policy is the proposed declaration of the Innamincka Regional Reserve, currently a 14 000 sq km pastoral lease within some of the most productive areas of PELs 5 & 6 held jointly by Santos Ltd. and Delhi Petroleum Pty. Ltd.It is intended that this new form of reserve will allow for the protection of specific areas of environmental sensitivity and of cultural, scientific and historic value, while still allowing for the continuation of pastoral, tourist and petroleum exploration/ production activity within the major part of the reserve area.
CAPITAL GAINS TAX — PRACTICAL ISSUES
Authors: Williamson M.L.
Published: August 2017

This paper is directed at the capital gains tax implications arising on the day-to-day transactions and events occurring within our industry.After explaining in very basic terms how CGT can be applied in our industry, I lead the oilman to an examination of more specific transactions, such as splitting tenements, renewals, extensions, subleasing and farm-outs.Some alarming issues arise that must be recognised by every 'dealsman' today. Parameters for deals are indicated along with thought processes to solve the problems to the extent they are solvable.As 19 September 1985 fades faster into the past, the CGT legislation is becoming more relevant as old pre- assets are converted into post-assets. The traps are there, and many people have already fallen - to their horror. The conversions are subtle but are there waiting.In this era of self-assessment and absurd tax penalties, tax audits and guilt until proven innocent, penalty minimisation is the name of the game, not tax avoidance.
THE CAMBRIAN TO PERMO-TRIASSIC ARAFURA BASIN, NORTHERN AUSTRALIA
Authors: Bradshaw John , Nicoll Robert S. , Bradshaw Marita
Published: August 2017

The Arafura Basin is on the northern margin of Australia, extending north towards New Guinea and contains a thick Cambrian to Permo-Triassic sedimentary sequence. The basin consists of a broad northern platform, a northwest trending graben, the Goulburn Graben (new name), and a southern platform that extends onshore into the Northern Territory. The basin sediments unconform- ably overlie the Proterozoic McArthur Basin and are overlain by mid-Jurassic and younger sediments of the Money Shoal Basin. The Palaeozoic section in the Goulburn Graben is over 10 km thick, while on the northern and southern platforms half that thickness is preserved.During the Cambrian and Ordovician the Arafura Basin was a stable platform dominated by carbonate deposition. The Late Devonian and Late Carboniferous aged sediments are marine and non-marine clastics with minor carbonates. Initial movement of the graben bounding faults occurred in the early Carboniferous, but the major graben development and deformation occurred in the Permo-Triassic and was associated with westward tilting.The six exploration wells in the basin have all been sited on structural targets along the Goulburn Graben. There were oil shows in most wells and four source rock intervals were intersected, but reservoir quality and fault seal were identified as major risks. The majority of the Cambrian and Permo-Triassic sequences remain untested and extensive areas of the basin outside the graben are virtually unexplored. Thermal maturation studies indicate a low geothermal gradient and that the greater part of the Palaeozoic sequence is prospective for hydrocarbons.
THE DEVELOPMENT OF THE HIDES GASFIELD, PAPUA NEW GUINEA
Authors: Renton J.F.A. , Black J.H.S. , Grainge A.M.
Published: August 2017

The Hides gasfield was discovered by BP, and its Joint Venture Partner Oil Search Ltd, in Petroleum Prospecting Licence No.27 in Southern Highlands Province in late 1987 by the exploration well Hides-1. The well tested gas at rates of up to 15.9 mmscf/d with small volumes of associated condensate from four separate intervals within the Toro Sandstone.Negotiations with Placer Dome, a Vancouver-based mining company, led to an agreement to sell gas to supply electrical power for the Porgera gold mine in Enga Province 70 km North East from Hides. Approximately 10 mmscf/d of gas will be produced from two wells, one being the original Hides-1 discovery well, via an 8 km pipeline, to a gas processing plant in the nearby Tagari valley. The processed gas will be fed to turbines to generate approximately 42 M W of electrical power which will be fed to the Porgera mine by overhead transmission lines.BP has undertaken technical studies relating to the feasibility of producing the gas from Hides. In association with the technical work BP has also undertaken an environmental study of the impact of development and has embarked upon a survey of various local and land-related issues. It is anticipated that construction operations will start in early 1990, leading to first gas production in mid-1991, only 3½ years after the discovery. The Hides gasfield development will constitute the first commercial hydrocarbon production in PNG.
THE SEISMIC EXPRESSION OF MIDDLE TO UPPER DEVONIAN REEF COMPLEXES, CANNING BASIN
Authors: Kemp G.J. , Wilson B.L.
Published: August 2017

This paper describes the unique seismic character of the Middle to Upper Devonian Pillara Limestone buildups as seen on seismic data acquired in the area northeast of the Pillara Ranges in the northern Canning Basin. The combination of high resolution 'vibroseis' acquisition techniques and relatively shallow depth of burial has enabled previously unattained definition of the reefs and the seismic facies variation associated with them. The lower bank, upper platform, fore- and back-reef facies and sediments of the overlying basinal flooding phase can be identified. The interpretation has been supported by the drilling of two exploration wells which have provided geological control in the subsurface.A model for the growth of the carbonate buildups and the relationship of this growth history to key phases of tectonism in the area has been developed from stratigraphic studies.A comparison with previous models for Devonian reef complexes in the Pillara is also presented.
SUBSURFACE FRACTURE ANALYSIS, PALM VALLEY GAS FIELD
Authors: Milne Nicholas A.
Published: August 2017

A comprehensive set of directional fracture data was obtained from the Palm Valley-7 well, central Australia, which has greatly added to the knowledge of the open fracture system which is present in and largely determines production rate from the Palm Valley gas field. The high quality of the Palm Valley-7 fracture data is attributed to the use of the recently introduced tools and techniques of recording down-hole core orientation data with an electronic survey tool, of measuring core fracture orientation at surface with an electronic goniometer linked to a lap-top computer and of acquiring wire-line microresistivity (dipmeter) data which can be analysed interactively to identify fractures and calculate their orientation. Open fractures at Palm Valley-7 have measured apertures of up to 3 mm. Inferred apertures of up to 10 mm are thought to exist. Open fractures occur to depths of at least 1800 m and dip at angles variably greater than 40° towards the south-southwest and west. Many fractures are wholly or partly mineralised; the mineral assemblage is complex, with dominant ankerite (ferroan dolomite), subordinate calcite and quartz, minor barite and traces of pyrite and iron oxides. Fracture orientation and density may vary considerably laterally between wells, vertically within a well and, at a particular point in a well, between different types of fractures. This variability is to some extent controlled by host rock lithology; for example, open fractures are largely confined to highly competent sandstones and dolomitic limestones and bedding plane fractures appear to be confined to less competent shales and shaley siltstones. Results of this study, when incorporated into an ongoing, larger field fracture study, should lead to an improved structural model for the field and an improved ability to site development wells to maximise the likelihood of such wells encountering open fractures in the reservoir section.
USE OF THE METHYLPHENANTHRENE INDEX TO CHARACTERISE EXPULSION OF COOPER AND EROMANGA BASIN OILS
Authors: Tupper N. P. , Burckhardt D. M.
Published: August 2017

The methylphenanthrene index (MPI) molecular maturity parameter is available for over 100 Cooper and Eromanga Basin oils. Oil maturity data define the threshold and range of expulsion maturity for source rocks and can be used to determine oil-source affinity. Mapping of this maturity range for all potential source rocks identifies areas of greatest oil potential.Cooper and Eromanga oils were expelled over a wide maturity range commencing at 0.6 per cent calculated vitrinite reflectance equivalent in some parts of the basin. Oil occurrence and expulsion maturity are controlled by variations in source quality such that no single expulsion threshold can be applied basin-wide. The full oil potential of the basin will only be realised by selective drilling of prospects with access to source rocks in the 0.60-0.95 per cent vitrinite reflectance range.The timing of oil expulsion is determined by using oil maturity data to calibrate thermal modelling of basin depocentres. Peak expulsion occurred during the Cretaceous and therefore prospects with pre-Tertiary structural growth are favoured.Structural embayments with thick Permian section at the southern margin of the Cooper Basin, plus the flanks of the Patchawarra and Nappamerri troughs, are highly prospective in terms of oil source potential and will be further evaluated by drilling in 1990.
TIMOR GAP ZONE OF COOPERATION
Authors: Smart Alan
Published: August 2017

On 11 December 1989 the Australian Minister for Foreign Affairs and Trade, Senator Evans, and the Indonesian Foreign Minister, Mr Alatas, signed the Treaty to establish a Zone of Cooperation in the Timor Gap.The Timor Gap Treaty is the most substantial bilateral agreement concluded in the forty year history of Australia's relations with Indonesia. The Treaty negotiations have developed a unique regime to allow joint control of petroleum exploration and development activity in Area A of the Zone, the area of joint development. The Treaty encompasses administrative, maritime and fiscal arrangements, customs, migration and quarantine, search and rescue, environmental protection and pollution control, criminal jurisdiction, employment regulation, marine scientific research, health and safety regulations and procedures for settlement of disputes.Work has now commenced to establish the Joint Authority which will be responsible for the administration of petroleum operations in Area A. Contracts in Area A will be awarded by a work program bidding system.
IN FOR THE LONG HAUL - 50 YEARS OF SHELL EXPLORATION IN AUSTRALIA
Authors: Thomas B.M.
Published: August 2017

On 27th November, 1939 Shell was awarded its first exploration concession in Australia. The initial holdings covered much of southern Queensland, including parts of the Eromanga, Surat and Bowen Basins. An exploration programme involving field geology, aerial photography, a gravity survey and shallow structural drilling preceded a 'deep test' in 1950, Morella-1, located in the Denison Trough near Springsure. In the course of the venture, Shell was responsible for the first effective application of several modern techniques to petroleum exploration in Australia, including geophysics, organic geochemistry and wireline logging. Although disappointing results led to relinquishment of this first area, Shell has continued to explore in Australia, initially through participation in the WAPET and North West Shelf consortia, and from 1962 in a series of other ventures throughout the country. The rewards, in terms of Shell equity reserves, total some 1.7 billion barrels of oil equivalent at an exploration cost since 1964 of 1.1 billion dollars (1988 equivalent value).
RESERVOIR DEVELOPMENT AND DIAGENESIS IN THE BASS BASIN, TASMANIA
Authors: Baillie Peter W. , Tingate Peter R. , Stuart William J.
Published: August 2017

Drilling and testing in the Bass Basin during 1985-86 indicated that reservoir quality of the lower Eastern View Group is one of the major factors determining the prospectivity of the basin. This study utilises an integrated sedimentological analysis to determine depositional environments of the various reservoirs, and documents the nature and effects that subsequent diagenesis has had on those reservoirs.During the Paleocene, deposition of the lower Eastern View Group took place within a progradational delta complex in a restricted marine environment. Sandstone bodies deposited in high-energy environments are the best potential reservoirs at depth. Thick, permeable reservoir sands occur in the northern sector of the basin as often-stacked, shoreline facies and in the southern sector as upper delta plain stacked point-bars.In medium- to coarse-grained quartzose sandstones good reservoir characteristics can be preserved down to depths of 3000 m. Variations in permeability in sandstones with high porosity are related to microporosity associated with pore-filling kaolin. Finer grained sandstones, with higher detrital illite and lower quartz contents, have little effective porosity preserved owing to compaction.
A NEW TECTONO-STRATIGRAPHIC SYNTHESIS OF THE NORTH WEST CAPE AREA
Authors: Malcolm R.J. , Pott M.C. , Delfos E.
Published: August 2017

The North West Cape area in the Exmouth Sub-basin was the site of the first onshore oil flow in Australia at Rough Range-1 in 1953. Subsequently, exploration focused on two large surface anticlines, Cape Range and Rough Range. By 1984, 30 unsuccessful wells had made it clear that the subsurface was far more complex than indicated by the surface mapping and limited seismic data. A detailed reappraisal of the subsurface structure and stratigraphy was needed.A joint venture group operated by Ampol Exploration began a new phase of exploration by recording over 1200 km of seismic data, both regional and detailed, between 1985 and 1989. An integrated interpretation of seismic data, well information and Landsat imagery has improved the understanding of structural and stratigraphic complexities and has given direction to the current exploration effort.Five of the most significant tectonic episodes to affect the North West Cape area have been recognised. They are Late Carboniferous and Early Jurassic (Sinemurian) rifting phases, Callovian-Oxfordian and Berriasian-Valanginian syn-rift pulses related to break-up and, finally, structural inversion in the Late Miocene. Each of these episodes is associated with characteristic structural styles and stratigraphic sequences.Significant lateral displacement along transfer faults during Sinemurian rifting and again during the Berriasian- Valanginian syn-rift pulse has resulted in the formation of tear faults that swing westward and merge with the plane of the transfer faults. Fault-block rotation and uplift associated with these tear faults provide potential structural and stratigraphic traps. The influence that transfer faults have on the hydrocarbon prospectivity of the North West Cape area has been recognised, including their role in the distribution of reservoir and source rocks.These tectono-stratigraphic concepts have provided a sound framework for future exploration in the North West Cape area, and may have implications for hydrocarbon prospectivity in other parts of the North West Shelf and on passive margins elsewhere.
SEISMIC AVO STUDIES ASSIST IN THE MAPPING OF A PERMIAN GAS SAND AT KERNA FIELD, COOPER BASIN
Authors: Pinchin J. , Mitchell A.B.
Published: August 2017

Kerna is a gas field within the south-central part of the Cooper Basin, 12 km southwest of the Dullingari Field and adjacent to the border of South Australia and Queensland. The trap is a domal anticline containing gas structurally trapped within the Early Permian Patchawarra Formation. The overlying Permian Epsilon Formation, above intervening shale, also contains gas, which may be stratigraphically trapped or restricted by permeability barriers around the southern and western flanks of the field.Seismic reflection amplitudes can be used to map the extent of the Epsilon gas sand. Seismic modelling studies show that the gas sand displays an amplitude-versus-offset (AVO) effect which distinguishes the gas sand from a wet sand or from a coal reflection at the same stratigraphic level. The spatial distribution of the AVO anomalies, and of the overall seismic stack response, has been mapped across the field. The interpreted 'seismic facies' map shows a meander belt across a coal swamp dominated flood plain. The distribution of AVO anomalies within and around this meander belt shows the likely occurrence of gas-bearing sandstones.This study has implications for other areas of the Cooper Basin where adequate separation between coal beds and gas sands allows the AVO effect of the latter to be observed. These AVO effects can then be used as a direct indicator of gas in stratigraphic and structural traps.
DEEP STRUCTURAL IMAGING FROM ONSHORE RECORDING OF A MARINE AIR-GUN SOURCE IN THE GIPPSLAND AND BASS BASINS
Authors: Collins C.D.N. , Cull J.P. , Colweli J.B. , Willcox J.B. , Williamson P.E.
Published: August 2017

In 1988 and 1989, the Bureau of Mineral Resources (BMR) completed two regional seismic reflection surveys in the Gippsland and Bass Basins. Seismic arrivals from the routine air-gun shots fired during these surveys were recorded on land by BMR and the Department of Earth Sciences, Monash University. Individual analogue and digital recording stations were deployed in Victoria, Tasmania and Deal Island on the Bassian Rise. Long-offset wide-angle reflection and refraction data were obtained at these stations from traverses across both basins.The data quality was variable, depending on local site conditions, but useful arrivals were observed over 200 km away from the source on some lines. The close shot spacing, either 37.5 or 50 m, and the large number of shots, up to 5000 per traverse, provides the opportunity for stacking and other signal enhancement techniques in areas of poor data quality.The arrival times of the refracted events show significant delays corresponding to changes in basin sediment thickness. Preliminary results suggest no major asymmetry in the rifting process, which would require modification in the current models for rifting of the basins. Sediment and basement apparent velocities obtained from near-station records range from 4.8 to 5.1 km/s; below the deepest part of the basin, the basement apparent velocity is around 5.6 km/s. Deep crustal/upper mantle velocities of 7.2 km/s, and around 8 km/s, are also observed.These velocities, combined with the coincident reflection data provide critical constraints on models of basement geometry. The refraction and wide-angle reflection data can be used to derive the crustal structure associated with the basins and surrounding margins. These sections will complement deep reflection profiling to test and refine tectonic models to guide further exploration.
FLUID HISTORY ANALYSIS — A PROSPECT EVALUATION
Authors: Eadington P.J. , Hamilton P.J. , Bai G.P.
Published: August 2017

Fluid history analysis investigates oil migration and basin hydrology which are important factors affecting hydrocarbon charge to reservoirs. A combination of direct observation and measurement at the mineralogical scale and numerical simulations is used.Fluid inclusions in diagenetic minerals are used to make direct observations about the timing of oil migration and to measure palaeotemperatures. Isotopic compositions of diagenetic minerals are measured for age determination and to identify the sources of ancient pore waters in order to interpret basin hydrology.Integrated interpretation of time specific and time dependent thermal indicators provides a detailed thermal history of the rocks as input to numerical simulations of oil generation. Hydrocarbon fluid inclusions provide an observational check on the theoretical predictions.In the Eromanga Basin in south-west Queensland two areas with different oil migration history are identified. On the Jackson-Challum trend there was a pulse of oil migration synchronous with quartz cementation in late Cretaceous time. On the Tintaburra-Bodalla South trend oil migration followed quartz cementation from the mid Cretaceous to the present day. Jackson oil migrated while the isotopic composition of pore water became increasingly oxygen-18 enriched indicating diagenetic modification during slow flow of groundwater. Tintaburra oil migration occurred during the present regime of downdip flow of relatively oxygen-18 depleted groundwater characteristic of a meteoric origin.
ONSHORE AND OFFSHORE PETROLEUM SEEPAGE: CONTRASTING A CONVENTIONAL STUDY IN PAPUA NEW GUINEA AND AIRBORNE LASER FLUOROSENSING OVER THE ARAFURA SEA
Authors: Martin B.A. , Cawley SJ.
Published: August 2017

Two case studies from the northern margin of the Australian continental plate are presented to illustrate mapping and understanding seepage in an onshore and an offshore area. The first involves an integrated approach to the detection and analysis of onshore seeps in the Aure Thrust Belt of Papua New Guinea. The second study is an application of BP's proprietary Airborne Laser Fluorosensor (ALF) technology to the systematic detection and mapping of offshore oil seepage in the Arafura Sea, northern Australia.In the absence of well or outcrop source rock data, the source risking in the Aure Thrust Belt has been constrained using oil and gas seeps. Mapping the seeps required optimum use of the local peoples' observational prowess. Geochemical analyses of the seeps allowed the identification of an oil-prone source rock of probable Jurassic age. The data reveal that the seeping petroleum liquids are gas condensates in the subsurface, and provide information on the maturation history of the source and the nature of the reservoir/carrier beds, as well as differentiating the biogenic and thermogenic gas components. In this uplifted region, seepage is likely to be from accumulations only.To help reduce the exploration risk in offshore areas such as the Arafura Sea, BP have developed the ALF system which detects oil seepage at the sea surface. It does this by detecting its characteristic fluorescence, which is induced by an aircraft-mounted ultraviolet excimer laser.The ALF data over the western Arafura Sea indicate active oil seepage showing a distribution which is compatible with our current understanding of the subsurface Palaeozoic and Mesozoic source kitchens. The mapped seepage over the Goulburn Graben is most likely derived from the Palaeozoic to (?)Triassic section (with a possible contribution from other Mesozoic sources), and must be migrating through a largely unfaulted Mesozoic seal. Additionally, there is evidence for liquid petroleum seepage from the Mesozoic section in the Calder Graben via faults which cut through the regional seal along the Lynedoch Bank Fault System. In this region of the Arafura Sea, seepage is likely to derive from accumulations, mature source kitchens and secondary migration routes.
CONTROL SYSTEM FOR REMOTE SUBSEA COMPLETIONS
Authors: Henry W.C.
Published: August 2017

The Seahorse and Tarwhine subsea completions are among a number of recent developments in Bass Strait designed to exploit relatively small and remote fields. Both wells have been developed by re-entering and completing the original exploration wells and tying them back to the nearest existing platform, Barracouta, with an insulated production flowline, a gas lift supply line, and an electrohydraulic control umbilical. Seahorse is a little over 11 km north, and Tarwhine almost 18 km south-west of Barracouta, and it is these long offset distances which significantly influenced the decision to adopt an electrohydraulic control system. The advantages of an electrohydraulic system in this application, compared to the other control techniques available, are that it provides a faster response time to surface initiated commands, it has an overall lower cost, and it provides information back to the surface about conditions at the subsea well.Many of the components used in the subsea production control system are innovative and highly specialised, for example, the conductive electrical couplers and the temperature transducers. A significant amount of the equipment also has its origins in the aerospace industry and, like in that industry, demands a high commitment to quality assurance and quality control throughout the manufacturing and assembly phases of the project. Seahorse and Tarwhine have now been producing successfully since September and May 1990, respectively. The success of this project gives the joint venture partners, Esso and BHPP, confidence to use subsea technology to continue developing smaller fields, particularly as developments move into deeper water approaching and beyond the edge of the continental shelf.
MARINE ENVIRONMENTAL MANAGEMENT OF THREE OFFSHORE OILFIELDS IN TROPICAL WATERS OF NORTH-WEST AUSTRALIA
Authors: LeProvost Ian
Published: August 2017

Environmentally safe management of hydrocarbon exploration and production activities is becoming increasingly important, particularly in sensitive marine areas. LeProvost Environmental Consultants have been working closely with Hadson Energy Limited, Western Mining Corporation Ltd and West Australian Petroleum Pty Ltd to produce environmental impact assessments, environmental management plans and monitoring programs for oilfields recently developed on the North West Shelf. Many of the well sites are located in areas with sensitive ecological habitats, including coral reefs, seagrass beds, mangroves and prawn spawning and fishing grounds. Consequently, operators in these areas have been required to produce comprehensive Environmental Management Plans and Oil Spill Contingency Plans, to gain development and operating approvals from the Western Australian Government.Formulation of these plans begins with baseline surveys of the biological, physical and social characteristics of the study area. Hydrodynamic modelling of the metocean conditions produces oil spill prediction envelopes to highlight the areas that may potentially be affected by an oil spill, if one should occur. Site-specific oil spill response procedures are then designed to cater for the sensitive marine habitats of the area, using the resources that are available in the region to deal with an oil spill.Results to date from the Marine Biological Monitoring Programs for three oilfields have supported predictions that no significant adverse impacts on the environment would result from the development and operation of the oilfields.
OCCUPATIONAL HEALTH AND SAFETY LAWS IN THE PETROLEUM EXPLORATION INDUSTRY
Authors: Hogan Greg
Published: August 2017

Recent legislation proclaimed in both Federal and State areas means that a distinct change is necessary in the implementation of safety and environmental policy. Traditional ideas about safety engineering with regard to both hardware and operating practices will be reassessed in the near future.A central theme running through most of the new legislation is to place an employee elected health and safety representative into a position carrying significant responsibility in the areas of defining safe working practices and also enforcing the adoption of safe working practices via statutory powers provided by the legislation.This discussion will compare and contrast various pieces of legislation, both Federal and State, which impact on the definition and implementation of safe work practices and safe work environments in the Petroleum Exploration Industry.
KIPPER—A UNIQUE OIL AND GAS DISCOVERY, GIPPSLAND BASIN, AUSTRALIA
Authors: Sloan M. W. , Moore P. S. , McCutcheon A.
Published: August 2017

The low side fault-dependent Kipper oil and gas discovery is unique in many ways:It is the first significant hydrocarbon discovery in the Golden Beach Group. The primary S-1 reservoir has a 328 m gross gas column with a 14 m gross oil leg, with estimated in place oil and gas volumes of 30 MMSTB and 750 BSCF respectively.The S-1 reservoir is top-sealed by a volcanic unit which is over 100 metres thick and separates the Golden Beach Group from the overlying Latrobe Group.Critical fault seal is interpreted to be dependent on the complex inter-relationship of Golden Beach Group stratigraphy: fluvio-deltaic S-1 reservoir sands juxtaposed against a thick lacustrine shale.S-1 reservoir geometry and continuity is complex, with significant lateral facies variation between Kipper-1 and Kipper-2.The Kipper discovery has focused attention on the Golden Beach Group play, and also proved the effectiveness of two very important prospect components for that play, i.e. regional volcanics can provide a competent top seal for hydrocarbons in the Gippsland Basin, and that fault-dependent prospects on the down-thrown side of the major basin margin faults can prove to be successful traps.
TANAMI-1 OIL DISCOVERY: BARROW SUB-BASIN
Authors: Beales V. , Howell E.A.
Published: August 2017

The Tanami oil discovery was made in 1991. The discovery well was drilled from an onshore location on Varanus Island and deviated into the offshore area. A small, 6.8 m oil column was intersected at the top of the Lower Cretaceous Flag Sandstone Member of the Barrow Group. Beneath the moveable oil, a residual zone of 19.8 m was encountered.Petrophysical, petrological and core analysis data indicate different reservoir properties in the moveable oil, residual oil and water zones. These results show that the oil in place has retarded diagenesis and associated reduction in porosity and permeability values.The residual oil column is interpreted to be a result of northward structural tilting in the early Tertiary, causing oil previously trapped to be spilled to the south.
STRATIGRAPHIC FRAMEWORK OF THE BARROW GROUP AND IMPLICATIONS FOR THE HYDROCARBON POTENTIAL OF THE WEST BARROW AREA
Authors: Ehrhard Leo W. , O'Reilly J. Brendan , Wulff Keiran J.
Published: August 2017

An integrated sequence stratigraphic approach has been used to resolve, with high resolution, the chronostratigraphy of the Barrow Group in the West Barrow area. Assessment of the hydrocarbon potential has resulted in identification of various play concepts and exploration risks.Five Barrow Group sequences are identified; each developed in response to tectonically or eustatically induced changes in sea level. The sequence stratigraphic framework provides an explanation for the distribution of reservoir and overpressure encountered in the area, and insight to the sealing potential within the Lower Barrow Group.Utilising the sequence analysis results, two strategies for geophysical mapping were established; structural mapping of reservoir/seal interfaces identified in Top Barrow and intra-Lower Barrow Group intervals, and secondly, amplitude mapping of seismic events associated with sandstones within the overpressured Lower Barrow Group. Amplitude extraction mapping of a seismic reflection generated by the submarine fan complex intersected by the West Barrow wells demonstrates a lobate areal geometry with well developed apparent channel axes. The occurrence of lobate sands within an overpressured shale, combined with hydrocarbon shows within the interval, highlight the stratigraphic potential in the area. Petrographic studies, however, indicate that diagenetic occlusion of pore space has downgraded the reservoir quality of these sands.At Top Barrow Group level, depth conversion of time structure maps using the midpoint depth technique has revealed structures not evident with time mapping. The largest closure encompasses the West Barrow-1A location where log analysis and gas homologue ratios indicate that a potential light oil/condensate hydrocarbon column may remain untested.
VULCAN SUB-BASIN FAULT STYLES — IMPLICATIONS FOR HYDROCARBON MIGRATION AND ENTRAPMENT
Authors: Woods E.P.
Published: August 2017

Several structural domains are recognised within the Vulcan Sub-basin, Timor Sea. These domains developed during the Jurassic rifting phase and are separated by major transfer zones which trend in a northwest-southeast direction. Within each domain are frequent third order transfers which sub-divide the main northeast trending fault blocks into numerous compartments. These enable structural hydrocarbon traps to be formed, despite a predominant regional dip. They also affect migration pathways.Jurassic fault styles include detached rotational blocks, salt-associated features, tilted fault blocks and 'hourglass' horsts and grabens. These generally have a northeast-southwest orientation. The transfer faulting complicates these features and forms zones of structural complexity with associated poor seismic data quality. A separate fault episode in the north of the sub-basin during the Tithonian resulted in an east-west fault set overprinting the earlier structuring.Intra-Cretaceous fault movement is also recognised and has an important role in early hydrocarbon entrapment.Structural reactivation during the Late Miocene/Early Pliocene of the earlier fault sets modified the geometry of many existing traps. Numerous new traps may also have formed as a result of this tectonism. In many places the resulting geometry is complex, particularly where the younger fault orientation is at an angle to the main Oxfordian fault set. The late-stage movement is primarily extensional, manifested by predominantly normal faults; overall, however, a varying component of strike slip is likely. A divergent strike-slip zone is recognised at the southwest end of the Cartier Trough.The effects of the late stage tectonism tend to mask the seismic expression of Mesozoic hydrocarbon traps resulting in many wells being drilled off-structure at the target horizon. An understanding of the deeper structuring should result in further discoveries in this prospective basin.
EXPLORATION IN PERMIT NSW/P10 IN THE OFFSHORE SYDNEY BASIN
Authors: Grybowski D.A.
Published: August 2017

The offshore Sydney Basin is unique frontier acreage because it is adjacent to Australia's largest gas and petroleum market on the east coast of New South Wales. Although the onshore Sydney Basin has been tested by more than 100 petroleum exploration wells, no wells have been drilled offshore.New South Wales Permit NSW/P10 has an area of 9419 km2 and extends over the offshore northern and central Sydney Basin which contains Upper Carboniferous to Middle Triassic lithiclastic and siliciclastic sedimentary rocks and volcanics. Maximum depth to magnetic basement in NSW/P10 is greater that 9 km in the southern Macquarie Syncline and south of the New England Fold Belt at the continental margin. Recent seismic reprocessing and aeromagnetic surveying have focused the exploration effort on northern NSW/P10 where thick (greater than 1600 m) Upper Permian section containing source and reservoir facies is predicted. Other areas in the permit are less prospective because of widespread intrasedimentary magnetic bodies or the absence by erosion of Upper Permian and Triassic section.The Sydney Basin is an exhumed basin that reached its maximum depth of burial in the Early Cretaceous prior to basinwide uplift of 1.5-3.5 km during the Tasman Sea rifting. The magnitude and timing of the exhumation can be demonstrated with fluid inclusion, magnetisation, fission track and vitrinite reflectance data. The presence of commercial quantities of oil or gas in Upper Permian reservoirs depends on trap integrity having been maintained during the epeirogeny, or the re-migration of hydrocarbon into new traps.
CASE HISTORIES OF COMPUTER MODELLING WITH A 2 MHZ DUAL RESISTIVITY MWD TOOL IN HORIZONTAL DRILLING
Authors: Krase S.J. , Wu J.Q. , Wisler M.M.
Published: August 2017

A technique has been developed to detect bed boundaries using a combination of computer modelling and real-time data from a 2 MHz dual resistivity MWD tool. This technique has proven effective in horizontal drilling projects in North America and Europe. Models of the response of a 2 MHz dual resistivity tool in high angle penetrations of various Australian reservoirs show the potential for application of this technique in Australian horizontal drilling projects.
SILICA DIAGENESIS AND PORE DEVELOPMENT IN PERMIAN SANDSTONES, SOUTHERN COOPER BASIN
Authors: Tingate P.R. , Luo P.
Published: August 2017

As the Cooper Basin is a mature petroleum province, more work is being directed towards further understanding the characteristics of the main reservoirs to maximise exploitation and recovery.To investigate the reservoir quality of Permian sandstones in the Cooper Basin, a study of the diagenesis and pore geometry has been carried out on the Toolachee and Patchawarra Formations in the Daralingie, Moomba and Della Fields. Following detailed petrography, scanning electron microscopy and cathodoluminescence observations, representative samples were selected for petrophysical analysis via mercury injection. The diagenetic studies show that early silica diagenesis has had a major impact on reservoir quality. Early quartz cement has helped rocks resist compaction so that primary porosity is preserved and allowed later porosity enhancement via dissolution.From petrophysical analysis, pores of different origin can be recognised and classified into three groups: inter-granular pore, kaolin framework pore and micropore groups. These groups can be distinguished quantitatively by their controlling pore throat radii. The radii for the various groups are ≥ 2.5 (µm (inter-granular), 2.5 − 0.5(µm (kaolin framework) and In the samples studied the relationship between the controlling pore throat radius (rpk) and permeability (k) is approximatelyk=rpk2Using this relationship, the calculated permeability associated with rocks containing only microporosity is less than 0.25 mD, making them unsuitable reservoirs. Permeability associated with the kaolin framework pore group ranges from approximately 0.25 to 6.25 mD, showing that it offers significant effective storage space for hydrocarbons, especially gas. The inter-granular pore group has variable permeability, ranging from near 6 to over 2000 mD. The causes for this variability are mainly diagenetic and include variable quartz cementation and different types of dissolution.Using the pore group division outlined above, different types of reservoirs can be distinguished. In addition, the results emphasise the importance of porosity within kaolin aggregates in Cooper Basin reservoirs and stress the need for adequate testing of initially unpromising horizons and careful choice of reservoir stimulation methods.
GEOMETRY OF RESERVOIR TRENDS IN THE EPSILON FORMATION SANDS, SOUTHERN COOPER BASIN, SOUTH AUSTRALIA
Authors: Fairburn W. A.
Published: August 2017

Sandstone reservoirs within the Lower Permian Epsilon Formation, despite being gas productive in several fields in the Cooper Basin of South Australia, in particular Big Lake and Moomba, have proved to be elusive targets for exploration. This is mainly due to the distribution pattern of these sands, which differs markedly from that of the thicker and laterally extensive fluvial sands which are prevalent in the Toolachee and Patchawarra formations. As a consequence, there has been some acceptance that the distribution of Epsilon Formation reservoirs are unpredictable.Log correlation studies of the Epsilon Formation, in conjunction with sand trend mapping, have identified sands which are either laterally continuous ('sheet' sands) or laterally discontinuous ('ribbon' sands).Core facies analysis supports the interpretation that the 'sheet' sands are lake shore strandline deposits whereas the 'ribbon' sands are distributary channel deposits of prograding delta systems.Based on the inferred depositional models, and with the aid of detailed isopach maps, it has been possible to project reservoir trends of the channel sands and prepare sand maps, at varying gamma-ray cutoffs, of the shoreface sands.An understanding of the geometry of the various sand bodies has clarified the prospectivity of the Epsilon Formation and facilitated the selection of development well locations throughout the Southern Cooper Bas