bluuebunny/crossref_metadata_2025 huggingface dataset:
HYDROCARBON OCCURRENCE AND DIAGENETIC HISTORY WITHIN PROTEROZOIC SEDIMENTS, McARTHUR RIVER AREA, NORTHERN TERRITORY, AUSTRALIA
Authors: Womer M.B.
Published: August 2017

The stratigraphy of the Proterozoic in the McArthur River area of Northern Territory consists of the basal, non-economic Tawallah Group, overlain unconformably by dolomitic carbonates and clastics of the McArthur Group, in turn overlain disconformably by Roper Group clastics. Several shows of tarry to brittle bitumen have been reported in sandstones of the Roper Group and in dolomites of the McArthur Group.In thin sections, the bitumen commonly displays shrinkage cracks, apparently associated with the loss of volatiles. Secondary minerals are observed infilling some of the cracks, indicating those phases of diagenesis which occurred subsequent to breaching of the hydrocarbon bearing reservoir. Additionally, the contact relationships of bitumen with the secondary minerals indicate a relatively early migration of hydrocarbons into the reservoir rocks.The inferred sequence for the McArthur Group dolomites is: early dolomitization and silicification, formation of vuggy (vadose) porosity, authigenic deposition of chalcedony at shallow burial depth, cementation by quartz at deep burial depth, migration of hydrocarbons (contemporaneous with sulphide formation), breaching of the reservoir, degradation of hydrocarbons, and deposition of sparry dolomite cement. The inferred sequence of diagenesis for Roper Group clastic reservoirs in this area is: authigenic deposition of minor quartz and illite cement, migration of hydrocarbon, breaching of the reservoir, major authigenic deposition of quartz and illite, degradation of hydrocarbon, and cementation by dolomite, hematite, and kaolinite.
TIRRAWARRA AND MOORARI ENHANCED OIL RECOVERY PROJECTS—‘GETTING MORE OIL OUT FROM DOWN UNDER’
Authors: Brown D.J. , Barley M.R.
Published: August 2017

The Tirrawarra and Moorari oilfields are located in the South Australian portion of the Cooper Basin. Production to date in the fields has been maintained primarily by infill drilling, with individual wells showing substantial declines in productivity. In the absence of an active aquifer, some form of pressure maintenance was required to arrest this productivity decline and increase recovery. The miscibility characteristics of the reservoir oil, the low rock permeability, and the availability of miscible injection gases made miscible gas flooding the preferred improved recovery process.In 1984 pilot gas injection floods were initiated in both the Tirrawarra and Moorari fields to test the effectiveness of pressure maintenance and the miscible process in the Tirrawarra Sandstone. Injection was initiated using the Tirrawarra Field non-associated Patchawarra Formation separator gas to defer the high facility costs associated with alternative injection gases.The results of the pilot injection programs have been most promising. Production has improved in most offset producing wells with no sign of early injection gas breakthrough. In 1986, expansion of the Tirrawarra pilot will complete development of a major portion of the Tirrawarra Field on inverted seven spot injection patterns. Ultimate development of the field for full scale injection may involve infill drilling and well conversions resulting in skewed five spot patterns. Three alternative injection gases are being considered: Patchawarra separator gas, carbon dioxide, and ethane, each of which show favourable miscibility characteristics with the Tirrawarra oil. The incremental oil recovery expected from the full development is 23 million stock tank barrels oil.
USE OF COMPUTER GRAPHICS: THE WEST KINGFISH POST DEVELOPMENT RESERVOIR SIMULATION STUDY
Authors: Younes A.M. , Morrell G.O. , Thompson A.B.
Published: August 2017

The West Kingfish Field in the Gippsland Basin, offshore Victoria, has been developed from the West King-fish platform by Esso Australia Ltd (operator) and BHP Petroleum.The structure is an essentially separate, largely stratigraphic accumulation that forms the western flank of the Kingfish feature. A total of 19 development wells were drilled from the West Kingfish platform between October 1982 and May 1984. Information provided by these wells was used in a West Kingfish post-development geologic study and a reservoir simulation study.As a result of these studies the estimated recoverable oil volume has been increased 55 per cent to 27.0 stock tank gigalitres (170 million stock tank barrels). The studies also formed the technical basis for obtaining new oil classification of the P-1.1 reservoir which is the only sand body that has been found in the Gurnard Formation in the Kingfish area.The simulation study was accomplished with an extremely high level of efficiency due to the extensive and effective use of computer graphics technology in model construction, history matching and predictions.Computer graphics technology has also been used very effectively in presenting the simulation study results in an understandable way to audiences with various backgrounds. A portable microcomputer has been used to store hundreds of graphic displays which are projected with a large screen video projector.Presentations using this new display technology have been well received and have been very successful in conveying the results of a complex reservoir simulation study and in identifying future field development opportunities to audiences with various backgrounds.
PERFORMANCE OF THE WALLUMBILLA LPG PLANT
Authors: Frith R.
Published: August 2017

Bridge Oil Ltd operates a turbo expander LPG recovery plant at Wallumbilla, near Roma, Queensland. Several novel techniques were adopted to ensure optimum performance under severe operating constraints caused by market characteristics and project economics. These were necessary to maximise recovery over a wide range of throughputs and rapidly fluctuating loads, whilst operating at the end of a two phase pipeline. Flexibility was achieved by recycling gas around the plant, and adopting appropriate control strategies to ensure rapid response to load changes.The project schedule was compressed into 15 months by skid-mounting equipment, and eliminating various activities from the project schedule. Final design was based entirely on feasibility concepts without preparation of a formal project proposal. Protection against delays from wet weather during site work was also gained by shipping fully fabricated process skids to site.Minor problems encountered after start-up were rectified for a cost considerably below the incremental revenues generated by the fast track construction philosophy.
SURFACE FACILITIES FOR OILFIELDS IN THE SOUTH AUSTRALIAN SECTOR OF THE COOPER BASIN
Authors: Scanlan R.J. , White C.J.
Published: August 2017

Delhi Petroleum Pty Ltd, as operator, has been responsible for the development of eight oilfields in the South Australian sector of the Cooper Basin since 1982. Some of these field developments are economically marginal, hence the need to optimise those aspects of the facilities which impact on the ongoing cost of production and the overall profitability. A phased development approach has evolved over the past three years to reduce the external financing requirements and to improve the certainty of the data used to define the key elements of each project.For the successful completion of the project a task force approach to project management is utilised, supported by the use of computerised project planning and control systems. Further, it is important to define and agree on the design criteria and philosophy for the project at the commencement, this providing a base by which to measure scope changes, and so that all concerned are working to a common goal.The use of economic analysis as a decision-making tool during all phases of the project assists the project team to home in on the key objective which is to maximise the project net present value. Comparative economics and sensitivity analysis are used at the conceptual stage to select the preferred development option, e.g. pipeline versus trucking.The design of surface facilities is dictated by a wide range of criteria including the above development philosophy. The variable nature of these criteria demonstrates that each new field development must normally be engineered individually to ensure the target of maximum net present value can be achieved.The Gidgealpa Crude Oil Development Project demonstrates the effectiveness of the above methodology and philosophies. The field was discovered in August 1984, and early production and trucking of oil commenced in January 1985 with 374 000 bbls produced prior to commissioning of the pipeline to Moomba in September 1985.
OIL PRICE OUTLOOK REMAINS UNCERTAIN IN THE FACE OF CONTINUING WORLD OVERSUPPLY
Authors: Story I.
Published: August 2017

Australia's oil industry has just emerged from the most difficult period in its short history, following the unprecedented collapse in world oil prices during the first half of 1986, and the continuing weakness during the rest of the year. As a result, the oil industry has undergone painful cost-cutting measures to survive the new environment. Thousands of jobs have been lost for good, exploration activity has been dramatically cut back to the levels of the late 1970s, and the industry now faces the bleak prospect that oil prices may not return to previous high levels until sometime in the 1990s, ironically at a time when Australian oil production is expected to begin a major decline.The Australian federal government has also felt the pain, through significantly reduced revenues from oil production and exports, although this has been anaesthetised to a large degree by a hike in petrol pump excise rates.Oil and petroleum product exports, which rose during the second half of 1985 to become Australia's number two export earner (behind coal) with sales valued at over $150 million a month, came to a dramatic halt during the first half of 1986 before resuming again at considerably lower levels during the second half, only after the government had lowered the top Bass Strait excise rate from 87 per cent to 80 per cent.Government revenue from Bass Strait excises, which reached a record $4.2 billion in 1984-85, fell slightly to $4 billion in fiscal 1985-86 and is forecast to tumble to $1.7 billion during 1986-87.The industry was granted a slight relief from the pressures of low oil prices during the second half of 1986 by the temporary scrapping of onshore levies and a reduction in the top Bass Strait levies. It was unclear, however, at the time of going to press just how long the government was prepared to continue with the tax holiday.The short to medium term outlook is far from healthy. The continuing world over-supply of oil is expected to last until at least the end of the decade, and perhaps into the 1990s. The OPEC nations continue to struggle with meeting the level of production ceilings which will ensure long term oil price stability. While signs are hopeful that OPEC may succeed in holding production at around 16-17 million barrels a day (mmbpd), continuing high output from the non-OPEC countries ensures the prospects for prices firming much above the US$15-18/barrel range for any length of time are not bright. The market supply/demand equation will ensure world prices remain precariously balanced for some time to come.
TAXATION CONSIDERATIONS FOR AN AUSTRALIAN COMPANY CARRYING ON PETROLEUM EXPLORATION AND DEVELOPMENT IN PAPUA NEW GUINEA
Authors: Wilson Peter A.
Published: August 2017

The Australian Income Tax Assessment Act, 19S6 (the Act) has recently been amended by the inclusion of a full foreign tax credit system (FTCS) to replace the partial and exempt system previously existing. In view of this change, and the increase in Australian participation in Papua New Guinea (PNG), petroleum exploration re-consideration of conventional corporate structuring into PNG is warranted.In considering the form of a tax effective structuring, it will be necessary to consider matters such as the following:obtaining an appropriate mix of debt and equity with the debt provided in a form so that the service fee will not qualify as interest for FTCS purposes;structuring the PNG operations through a subsidiary incorporated out of Australia, e.g. PNG;ensuring that the shareholding in the company is appropriate to enable a full credit for 'underlying taxes'; andobtain any 'tax sparing relief available due to the PNG treatment of interest and dividends.These aspects and the many other relevant planning points require consideration of complex legislation. In the absence of direct legal precedent, proper and full consideration is warranted if all intended financial benefits are to be obtained.
THE TECTONO-STRATIGRAPHY AND PETROLEUM POTENTIAL OF THE NORTHERN ABROLHOS SUB BASIN, WESTERN AUSTRALIA
Authors: Smith Greg C. , Cowley Robert G.
Published: August 2017

The Abrolhos Sub-basin lies offshore in Western Australia to the west of Geraldton and has geological affinities with the northern Perth Basin and the southern Carnarvon Basin. Both of these basins contain commercial petroleum accumulations, whereas the Abrolhos Sub-basin is a frontier area which is largely unexplored. A moderate seismic coverage of the sub-basin now exists but only two wells have been drilled, both of which were dry.Four main tectono-stratigraphic sequences are recognisable above Precambrian basement:Lower Palaeozoic Pre Rift SequenceCarboniferous-Permian Synrift/Rift Sequence S Triassic-Jurassic Rift Sequence4 Cretaceous to Recent Drift Sequence.The Lower Palaeozoic is only known on the eastern basin margins where it mainly consists of Silurian fluvial and alluvial fan red beds. The Carboniferous-Permian marine and coal measure volcanogenic synrift and rift sequences are characterised by north-south, mainly east-dipping extensional faulting, followed by widespread erosion. The Triassic sequence is about 2 km thick and comprises a basal marine Kockatea Shale, overlain by the marginal marine Woodada Formation and the Lesueur Formation red bed sequence. Subsidence during the Triassic was rapid but controlled by large NNW-SSE trending, high angle west-dipping, planar normal faults with minor rotation and extension. The Jurassic is poorly known, being confined to structurally deep blocks along the Mesozoic basin axis to the south and west. A renewed phase of NNW-SSE west-dipping extensional faulting began during the Jurassic and resulted in the development of rollover anticlines. Considerable erosion and non-deposition occurred forming a regional Neocomian unconformity. The postrift or drift sequence consists of transgressive marine shelf carbonates dipping basinward without further significant structuring.The main prospect types in the sub-basin include base Triassic transgressive sandstones or top Permian sandstones sealed by the Kockatea Shale in tilted fault blocks, and Triassic-Jurassic sandstones within rollover anticlines sealed by intraformational shales or the middle Jurassic Cadda Formation. The main source rocks include the Woodada and Kockatea formations which are within the oil generative zone over much of the sub-basin. However, identification of areas with the required coincidence of source, reservoir, seal and structural timing appears elusive.
HYDROCARBON POTENTIAL OF THE OFFSHORE OTWAY BASIN
Authors: Williamson P.E. , O'Brien G.W. , Swift M.G. , Felton E.A. , Scherl A.S. , Lock J. , Exon N.F. , Falvey D.A.
Published: August 2017

The Otway Basin is one of three sedimentary basins in the Bass Strait region and is situated west of the Bass and Gippsland Basins. It trends NW-SE, straddling the southern Australian coastline for 500 km between the Mornington Peninsula in Victoria and Cape Jaffa in South Australia. It has an average width of 200 km and an average offshore width, in water depths of less than 200 m, of 50 km.The offshore basin consists of three main tectonic units: the Mussel Platform in the east, the Voluta Trough, which occurs in the centre of the basin, and the Crayfish Platform in the west. Structures are formed predominantly by Cretaceous normal faults, downthrown to the continent-ocean boundary, and displacing landward-dipping Cretaceous strata. The sedimentary sequence can reach 10 km in thickness and consists of terrestrial Early Cretaceous sediments of the Otway Group, Late Cretaceous transgressive-regressive terrigenous sediments of the Sherbrook Group, Paleocene-Eocene transgressive-regressive, terrigenous and carbonate sediments of the Wangerrip and Nirranda Groups, and Oligocene-Miocene shelf carbonates of the Heytesbury Group.Since the early 1960s, about 50 exploration wells have been drilled onshore and 17 offshore. Shows of oil, gas and condensate have been widespread in both onshore and offshore wells, though only two small economic fields have so far been discovered; both are onshore. Exploration, particularly during the 1960s and 1970s, was hampered by poor seismic data quality, due primarily to the presence of shallow carbonates.
METHANE DRAINAGE POTENTIAL OF THE NORTHERN BOWEN BASIN
Authors: Bell R. M.
Published: August 2017

Large volumes of methane plus some other gases are generated during the coalification process. Under suitable conditions some of this gas is adsorbed within the microporosity of coals. The rate at which the gas can desorb is a function of the permeability, degree of fracturing or cleating, moisture content, geochemistry of the coals, and the pressure differential. Flow rates from coals are generally low but can be dramatically improved by artificial stimulation and techniques such as lateral drilling.Methane drainage or coal de-methanisation has been carried out for many years, primarily for safety reasons. The resource value of methane in coal seams is now being recognised and considerable research is being undertaken both overseas and in Australia.In the Northern Bowen Basin, several million tonnes of coal are mined each year. The main seams of the Permian Collinsville, Moranbah, German Creek, and Rangal Coal Measures are generally thick and laterally extensive. The area north of Blackwater probably contains more than 100 billion tonnes of coal from which several hundred billion m3 (several Bcf) methane could conceivably be recovered in those areas where the coals are too deep for commercial exploitation.The coals of the Northern Bowen Basin are considered to have better physical parameters for the commercial development of methane drainage projects than those of the central and southern Bowen Basin where methane drainage projects were undertaken several years ago. It is estimated that more than 85 million m3 (3 Bcf) of recoverable gas per square km could be present in some areas. This gas can probably be produced for less than $1.50/GJ (1 Mcft, a figure which compares favourably with many conventional natural gas sources.The Northern Bowen Basin is well-situated with respect to potential gas markets at Townsville and Gladstone. The gas could also be used as a chemical feedstock for products such as ammonia, fertilisers, explosives or synfuels, with the plants located close to the producing wells, thus significantly reducing gas transport costs.
FLOUNDER — A COMPLEX INTRA-LATROBE OIL AND GAS FIELD
Authors: Sloan M.W.
Published: August 2017

The Flounder Field is the deepest producing field in the Gippsland Basin. Since discovery in 1968 by Flounder 1, five delineation wells and 15 development wells have been drilled on the structure. The main T-1.1 oil and gas reservoir is trapped at the crest of a highly faulted anticline within the Latrobe Group. The Flounder structure has a complex deformational history with the Latrobe Group sequence undergoing two main phases of deformation. Late Cretaceous to Late Paleocene north-west trending normal faults are overprinted by a Late Eocene to mid Miocene north-east trending anticline. Generally within the Latrobe sequence in the Gippsland Basin, faulting destroys the integrity of the anticlinal features by breaking the lateral continuity of potential intra-formational seals. However, at the Flounder Field, the estuarine sands of the T-1.1 reservoir are overlain by a marine shale of adequate thickness to provide an effective seal across the faults.The T-1.1 oil and gas reservoir has excellent reservoir parameters. Separate gas caps are trapped in the multiple faulted crests of the structure and have had a major influence on the development of the field due to the resultant variation in gross oil column thickness.In addition, several small oil accumulations have been structurally and stratigraphically trapped in sediments filling the Tuna-Flounder Channel and the deeper Latrobe Group sequence.The Flounder Field commenced production in December 1984. Current estimated reserves for the T-1.1 reservoir are 155 billion cubic feet (BCF) (wet) gas and 115 million barrels (MMB) of oil, a dramatic increase over the 1978 pre-development estimated reserves of 86 BCF (wet) gas and 57 MMB oil.
HYDRAULIC JET PUMPING AT TINTABURRA OILFIELD
Authors: Biederstadt K.C.
Published: August 2017

The Hutton zone of the Tintaburra oilfield has an active bottom water drive which necessitates high gross fluid production rates to enable reserves to be produced within a reasonable period of time. A high volume artificial lift system capable of producing 8 000 to 10 000 barrels of fluid per day (BFPD) from 6 producing wells formed the basic design criteria, and hydraulic jet pumping was chosen as the means of artificial lift. The hydraulic jet pumping installation at Tintaburra was the first of its kind in Australia.The basic principle of operation of a jet pump is the transfer of momentum from a power fluid to reservoir fluid. The power fluid is pumped through a nozzle and the corresponding increase in velocity results in a pressure drop at the nozzle exit. This drop in pressure provides the drawdown necessary to move reservoir fluid to the pump where it is entrained and mixed with the power fluid. The combined stream is produced to surface and handled using convential production techniques. Equipment required in the Tintaburra system consists of a power fluid settling and storage tank, surface power fluid pump, distribution manifold, wellhead control valves and the subsurface assembly, including the jet pump itself.The application of mathematical equations describing jet pump operation was used in the initial selection of pumps for the Tintaburra wells. While this method provides insight into the operation of jet pumps, the use of equipment supplier's software proved to be more expedient in the final design stages and allowed many nozzle and throat combinations to be evaluated. Changes to well productivity brought about by the installation of down hole equipment required new pump selections for all wells. After nine months of operation, comprehensive production testing again highlighted changes to well productivity, necessitating variations in operating parameters or, in some cases, specification of new pumps.
HORIZONTAL DRILLING, A NEW PRODUCTION METHOD
Authors: Bosio Jacques
Published: August 2017

Vertical or deviated wells cross a production formation for only short distances. Horizontal wells, however, are capable of remaining within a reservoir for distances up to several hundred metres in an effort to enhance production possibilities.A world-wide coverage of the method will be presented, with the latest information on drilling, logging, completion and costs.Application of horizontal wells will be described with an emphasis on the production results recently obtained and, more particularly, on the Rospo Mare field, offshore, in the Adriatic Sea.Horizontal wells are providing a new approach to the flow geometry within a production formation. There is no doubt that they will be used more and more in the future to optimise the drainage of most reservoirs.
THE INTRA-LATROBE PLAY : A CASE HISTORY FROM THE BASKER/MANTA BLOCK (VIC/P19), GIPPSLAND BASIN
Authors: Clark A.B.S. , Thomas B.M.
Published: August 2017

In 1981 Shell and its co-venturers were the successful applicants for gazettal block V80-3, now permit VIC/P19, on the north-eastern margin of the Gippsland Basin where, subsequently, 10 exploration wells were drilled. At the time of the award, the offshore Gippsland Basin had been explored for some 20 years, and the conventional 'Top Latrobe' play even then was considered to be largely exhausted although a few small traps of doubtful economic viability remained untested. Thus, from the outset, exploration in VIC/P19 also emphasised the intra-Latrobe play. While the existence of the intra-Latrobe play has long been recognised, its extent and limiting parameters are less well documented.Recent exploration results in the southern part of VIC/P19 indicate that the main phase (peak) of generation and expulsion of hydrocarbons from intra- Latrobe source rocks occurs at depths of 4 to 5 km for oil and 5 to 6 km for gas. Large-scale vertical migration of hydrocarbons (up to 2 km or more) is probably occurring in many parts of the central Gippsland Basin and has charged faulted intra- Latrobe traps, such as found at Basker-1 and Manta-1. These accumulations are characterised by multiple stacked reservoirs (fluvial and alluvial sandstones) and thin hydrocarbon columns. However, similar adjacent traps are dry, despite the presence of equivalent reservoirs (e.g. Basker South-I and Chimaera-I), probably due to inadequate lateral fault seals. Lateral sealing may occur along the fault plane itself or by favourable juxtaposition of lithologies, both cases being demonstrated in the Manta accumulation. The petrology and reservoir characteristics of Latrobe Group sandstones vary considerably, depending largely on sedimentary facies. Sands of fluvial or alluvial origin are generally inferior to those deposited in shoreline environments. An effective intra-Latrobe reservoir 'floor' lies at around 4 km burial depth for both fluvial and alluvial sandstones.
AUSTRALIA'S PETROLEUM PROSPECTS: CHANGING PERCEPTIONS SINCE THE BEGINNING OF THE CENTURY
Authors: Robertson C.S.
Published: August 2017

Perceptions of Australia's petroleum prospectivity, both by the general public and by professional explorationists, have changed considerably over the years. By the 1920s there had already been a considerable change from the optimism of the early part of the century, engendered largely by gas and condensate indications in water bores drilled in the Roma area, to a comparatively pessimistic view due to the failure of numerous small drilling ventures, and to the published opinions of some overseas experts.The public then remained generally apathetic or pessimistic about Australia's petroleum future until the Rough Range discovery in 1953 finally dispelled the myth that Australia was barren of producible oil. Rough Range proved to be the first of a series of discoveries which significantly upgraded industry and public perceptions of Australia's petroleum potential.Other particularly significant discoveries were the Moonie oilfield in 1961, the Gidgealpa and Barracouta gas fields in 1963 and 1964, the giant King-fish and Halibut oilfields in 1967, gas/condensate and oilfields on the North West Shelf in 1971, the Strzelecki and Fortescue oilfields in 1978, and the Jabiru oilfield in 1983. Exploration of the Exmouth Plateau from the early 1970s onwards initially caused a significant increase in estimates of Australia's petroleum potential, followed by downward revisions in the early 1980s because of the failure of the Plateau to live up to expectations.Perceptions of the prospects of some individual basins have also changed dramatically with time. Notable examples are the onshore Carnarvon Basin, the Georgina Basin and the Eromanga Basin.The most significant change in methods of assessing Australia's prospectivity was the introduction of quantitative, probabilistic methods in the 1970s. BMR's current assessment is that we can expect to find an additional 2 400 million barrels of oil, 23 trillion cubic feet of gas, and 550 million barrels of condensate on the Australian continental plate (average estimates).
STRUCTURE AND DEVELOPMENT OF THE OTWAY BASIN
Authors: Yu S.M.
Published: August 2017

The Otway Basin developed as a series of extensional basins along the southern margin of Australia during the Late Jurassic and the Early Cretaceous, prior to the break up of Eastern Gondwanaland. The Basin developed initially as a rift which subsequently, Middle Cretaceous time onwards, drifted and separated.The structural framework of the Basin is very complex due to the superposition of various successive tectonic processes that resulted in a series of predominantly north-west-south-east striking, basin dipping faults. Strike directions of the faults progressively change to a more north-south direction off Tasmania. In addition, in the area east of Cape Otway, the predominant strike trend changes to a north-east- south-west direction.Previous models for the development of this complex Basin have all invoked an east-west right lateral wrench system across south-eastern Australia. However, results from recent seismic mapping of the basin have indicated that some features present exhibit components of east-west left lateral movement. Many younger features, particularly in the east, also exhibit recent reverse fault movements.The author interprets that a right lateral east-west couple was active during the early part of the basin development. However, many of the features and trends observed can be better accounted for by the presence of a north-south striking wrench system which has induced an apparent east-west left lateral movement. Such a wrench system is present in the Southern Ocean, where a series of north-south striking transform faults have developed as a result of relative movement at the Southern Ocean spreading centre. Lateral movements across these transform faults have played a major role in the development of some of the observed features within the Basin.
THE OIL AND GAS LABOUR MARKET — AN OVERVIEW
Authors: Bogan Ronald
Published: August 2017

Over the past four years the Australian Oil and Gas Exploration Industry has moved from a period of high exploration and development, skill shortages and overseas recruitment, through to a period of declining levels of exploration activity and expenditure, low world prices and significant retrenchments.A number of manpower and training aspects of industry development and decline over the period 1980 through to 1987 are discussed.The paper reviews and examines aspects of the Australian oil and gas work force and labour market. It brings into sharp focus a number of critical training and professional development issues facing the industry today. It proposes a review and rationalisation of academic programs for geoscientists and planning for future manpower requirements for the industry.
OPEC AND THE OUTLOOK FOR OIL PRICES
Authors: Rothman Michael
Published: August 2017

Where are the crude prices going? OPEC has certainly made progress toward restoring its own credibility as well as an environment of stable prices, but there are still factors that point to a future of both price volatility and fragility. This paper will examine the supply/demand outlook with an emphasis on intra-OPEC dynamics and cartel policies, and the likely impact on crude prices. As part of the discussion, we will look at the implications of shifts in the Iran/Iraq situation, likely cartel responses, and the effect of the supply balance from the Middle East.
AUSTRALIA'S ECONOMIC RESTRUCTURING AND ITS POTENTIAL IMPACT ON PETROLEUM EXPLORATION
Authors: D'Arcy M.G.
Published: August 2017

Changes in the structure of a modern economy are a natural function of altered world and domestic economic circumstances. It is important that the instrument of change be the marketplace. Governments around the world have not demonstrated a superior ability to 'pick winners'. There are many instances where governments have used public funds to foster the development of particular industries only to find that, as a result of economic circumstances, the favoured industries' reliance on public funding becomes chronic. The Government's role should be to ensure that market signals are transmitted and received clearly.In Australia structural change in the economy has been a fairly slow process. This has been brought about by the numerous obstacles that have existed in the marketplace. These have meant that, not only were market signals distorted or delayed, but when received did not motivate appropriate responses. For example, labour market rigidities, inequitable taxation policies, a fixed exchange rate, together with State Government charges, have posed real impediments to implementing the necessary adjustments to the Australian economy.The Australian mining industry and the petroleum industry, in particular, have always been geared to the world market and have increasingly constituted an important component of the nation's export receipts. With regard specifically the petroleum industry, the world price downturn of the past few years and the Government's decision to drop its import parity pricing will result in major changes in the Australian industry, particularly in the exploration sector. These signals suggest a world oversupply of petroleum with the corollary that additional reserves are not needed. A resultant downturn in exploration could develop into an irrevocable reversal and jeopardise the nation's strategically important petroleum industry.In light of the diminished circumstances of the sector it is essential that the petroleum industry receives equal treatment regarding taxation and other Government imposts. Failure to remove the discriminations against petroleum and to impose a uniform structure will result in a misallocation of resources and the possibility of a permanent winding down in exploration.
LONG-TERM PERSPECTIVES FOR THE AUSTRALIAN GAS INDUSTRY
Authors: Tormasi T.
Published: August 2017

Changes in the structure of a modern economy are a natural function of altered world and domestic economic circumstances. It is important that the instrument of change be the marketplace. Governments around the world have not demonstrated a superior ability to 'pick winners'. There are many instances where governments have used public funds to foster the development of particular industries only to find that, as a result of economic circumstances, the favoured industries' reliance on public funding becomes chronic. The Government's role should be to ensure that market signals are transmitted and received clearly.In Australia structural change in the economy has been a fairly slow process. This has been brought about by the numerous obstacles that have existed in the marketplace. These have meant that, not only were market signals distorted or delayed, but when received did not motivate appropriate responses. For example, labour market rigidities, inequitable taxation policies, a fixed exchange rate, together with State Government charges, have posed real impediments to implementing the necessary adjustments to the Australian economy.The Australian mining industry and the petroleum industry, in particular, have always been geared to the world market and have increasingly constituted an important component of the nation's export receipts. With regard specifically the petroleum industry, the world price downturn of the past few years and the Government's decision to drop its import parity pricing will result in major changes in the Australian industry, particularly in the exploration sector. These signals suggest a world oversupply of petroleum with the corollary that additional reserves are not needed. A resultant downturn in exploration could develop into an irrevocable reversal and jeopardise the nation's strategically important petroleum industry.In light of the diminished circumstances of the sector it is essential that the petroleum industry receives equal treatment regarding taxation and other Government imposts. Failure to remove the discriminations against petroleum and to impose a uniform structure will result in a misallocation of resources and the possibility of a permanent winding down in exploration.
APPLICATION OF THE DETACHMENT MODEL FOR CONTINENTAL EXTENSION TO HYDROCARBON EXPLORATION IN EXTENSIONAL BASINS
Authors: Etheridge M. A. , Symonds P. A. , Powell T. G.
Published: August 2017

The extension of the continental lithosphere that gives rise to continental rifts and eventually to passive continental margins and their basins is considered generally to involve shear on one or more major, shallow dipping normal faults (detachments). The operation of these detachments induces a basic asymmetry into the extensional terrane that is analogous to that in thrust terranes. As a result, the two sides of a continental rift and conjugate passive margin segments are predicted to have contrasting structure, facies development, subsidence history and thermal evolution.The major structural consequence of the detachment model is that half- graben rather than full graben geometry is expected in rift basins, consistent with recent interpretations in a wide range of continental rifts and passive margins. Half- graben geometry dominates in the Bass Strait basins, the Canning Basin and in a number of Proterozoic rifts, and has been observed on most parts of the Australian continental margin. Variations in the along- strike geometry of extensional basins are accommodated by transfer faults or fault zones. Transfer faults are as important and widespread in rifts as the classical normal faults, and they have important consequences for hydrocarbon exploration (e.g. design of seismic surveys, structural interpretation of seismic data, play and lead development).The fundamental asymmetry of extensional basins, and their compartmentalisation by transfer faults also control to a large extent the distribution of both source and reservoir facies. A model for facies distribution in a typical rift basin is presented, together with its implications for the prime locations of juxtaposed sources and reservoirs. Maturation of syn- rift source rocks depends on both the regional heat flow history and the amount of post- rift subsidence (and therefore burial). Both of these factors are influenced, and are partly predictable by the detachment model. In particular, there may be substantial horizontal offset of both the maximum thermal anomaly and the locus of post- rift subsidence from the rift basin. Analysis of deep crustal geophysical data may aid in the interpretation of detachment geometry and, therefore, of the gross distribution of thermal and subsidence histories.
THE KALLADEINA FORMATION – A WARBURTON BASIN CAMBRIAN CARBONATE PLAY
Authors: Roberts D.C. , Carroll P.G. , Sayers J.
Published: August 2017

The Warburton Basin is currently considered economic basement to the gas-oil productive Cooper Basin and the oil productive Eromanga Basin. Only 10 wells have penetrated more than 100 m of the Kalladeina Formation which is identified as the most prospective section within the Warburton Basin. The Kalladeina Formation consists of more than 1600 m of carbonate shelf sediments deposited during the early Cambrian to early Ordovician in a basin consisting of half grabens on the continental side of an active margin.Several intra-Kalladeina Formation seismic events in a 500 km2 region to the west of the Gidgealpa oil and gas field have been tied to wells with palaeontological control. Structure and isopach mapping illustrates large scale thrusts, wrench fault zones and subcrop edges for the Kalladeina Formation. Maps of unconformities and of formations above the Warburton Basin define source, seal and trap relationships.Good carbonate reservoirs have been identified in the Kalladeina Formation but the source potential of this succession appears to be restricted. The overlying Cooper Basin source rocks may have charged the underlying carbonates and this represents one of three play types identified in the area.All Warburton Basin plays are very high risk but potential reserves are also large.
LOWER CAMBRIAN RELIEF SANDSTONE, EASTERN OFFICER BASIN, SOUTH AUSTRALIA: AN EXAMPLE OF ECONDARY POROSITY DEVELOPMENT
Authors: Gaughan Chris J. , Warren John K.
Published: August 2017

Interest in the Relief Sandstone as a potential economic oil-bearing sandstone is supported by excellent reservoir quality (up to 26.6 per cent porosity and 4839 md permeability). Potential source rocks are found above, below and interfingering with the Relief Sandstone. There are several occurrences of live oil bleeding from vugs and fractures in a stratigraphically higher carbonate. Traces of oil in the Relief sands, and the presence of live oil in relatively close proximity, suggests that the Relief Sandstone could host an economic oil accumulation.The majority of the Relief Sandstone was deposited in aeolian or braided fluvial environments with some tidal to shallow marine deposition in the west. Distribution of reservoir-quality sands is bimodal. In the east, porosity and permeability for the most part is very poor to average. In the west, porosity and permeability is generally good to excellent. The bulk of the economic porosity is secondary, a result of dissolution of cement and matrix, with minor porosity from leaching of grains. The lower reservoir quality in the east is due to diagenesis associated with compaction and authigenic illite. In the west, the porosity and permeability are high and generally due to dissolution of clay cement and primary matrix. In some cases where the clay has undergone less dissolution, it remains as grain rims and still blocks pore throats. This significantly reduces permeability although the porosity may remain high.
PROSPECTIVITY OF THE OTWAY SUPERGROUP IN THE CENTRAL AND WESTERN OTWAY BASIN
Authors: Kopsen E. , Scholefield T.
Published: August 2017

Recent hydrocarbon discoveries in the non-marine rift fill sequence of the Otway Basin at Windermere, Katnook and Ladbroke Grove have upgraded the importance of this relatively poorly known interval of the sedimentary column and provide hydrocarbon trapping models for future exploration. Using a seismic stratigraphic approach based on high resolution seismic data and the geological re-evaluation of many key early wells, a clearer pattern has emerged for the distribution of major reservoir and seal units.The best reservoirs occur in the Crayfish Group 'A', 'B' and 'D' units and the Windermere Member of the Lower Eumeralla Formation. One of the most critical elements in controlling the more prospective areas is the diagenetic characteristics of the main hydrocarbon objective units. Reservoir quality is significantly affected by the abundance or absence of volcanic detritus and depth of burial, and as a result, the most attractive reservoir is the Crayfish 'A' lying at depths shallower than 3000 m. Lateral fault seals and good vertical seals are present at various stratigraphic levels through the sequence for the development of effective traps in fault blocks and anticlines.The Casterton Group and the basal coal measures zone of the Lower Eumeralla Formation overlying the Windermere Member are identified as the most prospective oil sourcing units in the sequence. Secondary oil sourcing intervals occur within the Crayfish 'C' unit and at the top of the Lower Eumeralla Formation. A higher drilling success rate is now expected in the future with hydrocarbon fairways in the supergroup expected to comprise:Fault blocks and anticlines in the more basinal areas, e.g. the Katnook and Ladbroke Grove gas fields.The 'shoulders' of the main rift depocentres where fault traps will be most prevalent, e.g. the Kalangadoo CO2 discovery.Portions of the northern platform lying on migration pathways extending from the main graben (hydrocarbon kitchen) areas.
INTRODUCTION OF NEW TECHNOLOGY INTO TIMOR SEA OPERATIONS
Authors: Bond D. , Brock N. , Chapman G. , Lay K. , Wormald G.
Published: August 2017

The Timor Sea is the most remote and under-explored oil province in Australia. In order to compensate for the high exploration costs which result in frontier areas, new technology has been introduced by BHP Petroleum in order to increase drilling efficiency, assist in well evaluation and enhance the reliability of production technology. Examples of innovation and the importation of advanced techniques into the Timor Sea region are discussed. Advanced mud systems and PDC bit designs have been developed to aid the drilling of wells. Measurement While Drilling tools and tritium tracers have been used to enhance correlation and evaluation techniques. Equipment and procedures which emphasise the philosophy of reliability and longevity have been developed for sub-sea completions. These innovations have not only assisted with cost reduction, but have also enhanced BHP Petroleum's exploration and production success in the Timor Sea.
OFF-END SEISMIC DATA ACQUISITION IN THE EROMANGA BASIN
Authors: Gisolf A.
Published: August 2017

During late 1988 and early 1989 Shell conducted a land seismic survey in permit ATP 267P in the Eromanga Basin, in fulfilment of farm-in obligations. Against traditional wisdom in the Eromanga Basin Shell decided for an off-end acquisition geometry.An acquisition geometry design rationale is presented which leads to an optimum stack response. Depending on geological and economical constraints on maximum offset and shot and receiver station spacing this may result in either a split spread or an off-end geometry.For Shell's Eromanga seismic campaign it was decided that, given a 120 channel seismic recording instrument, an off-end spread with 15m source and receiver station spacing and 1800 m maximum offset presented the best compromise between optimal achievement of exploration objectives and available resources.For comparison an 8 km portion of a nearby 1988 centre spread line was overshot using the off-end technique, and was processed by the same contractor with a similar processing sequence. The improvements in data quality obtained demonstrate that off-end data acquisition is a viable technique which can be optimally suited to meet lateral sampling and noise suppression requirements.
A NEW METHOD FOR ASSESSING THE THERMAL HISTORY OF SEDIMENTS: A CASE STUDY FROM THE EXMOUTH PLATEAU IN NORTHWESTERN AUSTRALIA.
Authors: Alexander Robert , Marzi Roger , Kagi Robert I
Published: August 2017

The Jupiter-l well on the Exmouth Plateau is presented as a case study to illustrate the use of a new molecular geochemical approach to assessing thermal history. This approach involves measuring the extent to which six independent molecular processes have occurred in a sediment column. The rates at which these molecular processes occur are well known from controlled laboratory studies; by measuring the extent to which each molecular process has occurred at a number of points in the sediment column, it is possible to identify a thermal history which is consistent with these geochemical constraints and the known geology of the sediment column. In the present study, this approach revealed that the heat flow which best accounts for present day temperatures and maturity involved a comparatively low heat flow of not more than 1.1 HFU until approximately 88 Ma before present, followed by an increase to 1.3 HFU which has continued until the present day.