bluuebunny/crossref_metadata_2025 huggingface dataset:
A REGIONAL INTERPRETATION OF THE BROWSE BASIN
Authors: Allen G. A. , Pearce L. G. G. , Gardner W. E.
Published: August 2017

The Browse Basin, off the northwest coast of Australia, originated as an intracratonic basin. It resulted from tensional movements and developed into an Atlantic-type continental margin. Sedimentation, which commenced in the Late Carboniferous and extended through the Middle Jurassic, is confined mostly to a linear, northeast-trending depocentre located between the onshore Kimberley Block and the Scott Plateau to the west. This sedimentary series is characterised by rift valley type deposits laid down between successive episodes of tectonism. Tectonism near the end of the Middle Jurassic was associated with breakup of the continent along what developed as the seaward edge of the Scott Plateau. This geological event marks an important change in the depositional environment of the basin from pre-breakup, mainly paralic and fluviodeltaic to post-breakup, transgressive marine conditions. The post-breakup series was formed under relative tectonic quiescence, except for some local structural rejuvenation and regional subsidence of the outer continental margin which eventually resulted in the deposition of Cretaceous and Tertiary sediments across the Scott Plateau. A fully open marine environment, however, was not achieved basinwide until during the Late Cretaceous, when the Scott Plateau had subsided sufficiently to allow unrestricted ocean circulation. Evolution of the basin was completed by a seaward prograding, mainly carbonate Tertiary wedge.Geophysical data show several sub-parallel, structurally high Mesozoic trends, oriented towards the northeast. The Scott Reef gas/condensate discovery lies on one such trend. The structural elements were interpreted as being mostly initiated prior to breakup by episodes of block faulting which produced a horst and graben topography. The horst blocks were subsequently onlapped and draped by the post-breakup sediments. The hydrocarbon accumulation at Scott Reef is restricted to the horst block reservoirs, but hydrocarbon indications elsewhere within the basin in the post-breakup series suggest that accumulations could also exist in this section.
SEA LEVEL CHANGES IN THE NEOGENE OF SOUTHERN VICTORIA
Authors: Mallett C. W.
Published: August 2017

The distribution and lithology of marine sediments in southern Victoria are related to climatic events and the associated sea level changes. The most extensive transgression on the northern (onshore) margin of the southern Victorian Tertiary basins occurred late in the Early Miocene, with widespread deposition of calcareous muds and localised calcarenites with Lepidocvclina. Shallowing at approximately 14 m.y. affected all southern Victoria, initiating lithological changes in the Otway and Port Phillip Basins, and coinciding with erosion in the Gippsland Basin. Throughout the Late Miocene the grain size of sediments tended to increase and cross-bedded calcarenites became more common, consistent with shallowing deposition and sea withdrawal. By approximately 6 m.y., near the end of the Late Miocene, the sea had completely withdrawn from the onshore areas of southern Victoria.Pliocene and Pleistocene outcrops are scattered and thin, and marine beds are exclusively of nearshore and shallow deposition. For much of this period sea level was lower than at present. High levels in the Pliocene are indicated at approximately 5 m.y. and 3.5 m.y. High sea levels, associated with the rapid alternation of glacial and interglacial periods which typify the Pleistocene Epoch, were initiated late in the Pliocene, close to 2 m.y.Changes to the planktonic foraminiferal faunas parallel the sedimentological responses to sea level change. These suggest that palaeoclimatic events were the main controlling factor in Neogene sea level changes in southern Victoria, and allow differentiation of the eustatic and tectonic controls on sedimentation.
THE APPLICATION OF GRAVITY INTERPRETATION TO AN INTRA CRATONIC BASIN
Authors: Dampney C. N. G. , Johnson B. D. , Hollingsworth R. J. S.
Published: August 2017

I he Cooper Basin is a good example of a tectonically complex area, and this complexity is reflected in the gravity field. The gravity field caused by the sediments is distorted by the influence of a relatively strong regional field. Nevertheless along profiles over which gravity has been measured with appropriate care, the various components of the gravity field can be analysed and separated.In the Cooper Basin the form of the regional field has been determined. As a result the structure of a major pre-Permian unconformity, which defines the base of the sediments mainly causing the gravity field anomaly, can be contoured. Other information related to some shallow structure is also derived.The pertinent point emphasized by the Cooper Basin example is that over similarly complex areas gravity survey results can only be effectively used once the various components of the field are properly analysed. Scattered regional measurements may be of some value where the regional field varies little. In general, however, a few detailed profiles must also be available to upgrade gravity interpretation to the level where it is of immediate value in the early stages of oil exploration.Specifications are therefore presented which detail gravity, elevation and positioning measurement accuracy as well as survey procedures necessary to detect geological structure at given depths.
THE ORGANIC GEOCHEMISTRY OF OIL AND GAS GENERATION AND ITS APPLICATION TO BASS STRAIT AND THE NORTHWEST SHELF
Authors: Saxby J. D
Published: August 2017

A study of the chemical reactions occurring within the geological environment can throw new light on the occurrence of petroleum and natural gas deposits. The principles of chemical kinetics enable extrapolations to be made so that the depths and temperatures of typical hydrocarbon-forming reactions can be deduced when intervals of geological time are available. In general, temperature is the crucial parameter with corrections being possible for shorter or longer heating times.Living organic matter available for incorporation in sediments is of four basic types: carbohydrates, proteins, lignin and lipids. Only the last two are significant precursors of organic matter (kerogen) in consolidated sediments. Lipid-derived material is the principal source of oil, while lignin-related kerogen gives methane as its main gaseous hydrocarbon product. Generation occurs in zones where the rate of cracking of the source material into volatile hydrocarbons due to increasing temperature becomes significant on the geological time-scale. During and after migration of oil from its source to reservoirs (usually at shallower depths and lower temperatures), other processes can alter the initial light oil. In particular, biodegradation by microorganisms can result in a heavier naphthenic or aromatic crude by the loss of normal alkanes.Application of organic geochemistry to specific basins involves the measurement on uncontaminated core samples of certain parameters (organic carbon, extractable hydrocarbons, normal alkane distributions, reflectance of vitrinite, H/C ratio of kerogen and spore coloration). These data, together with activation energies for specific chemical reactions, geothermal gradients, rates of subsidence and knowledge of the geological history of the basin enable a general view of generation, migration and preservation of oil and gas to be obtained. Such an overview is given for the Gippsland Basin, where generation of both oil and gas in the lower Latrobe Group is indicated, and for the Rankin Platform of the Northwest Shelf where a deep source at greater than 4000 m is suggested for the gas and condensate.
ROLE OF GEOMICROBIOLOGY IN ENHANCED RECOVERY OF OIL: STATUS QUO
Authors: Bubela B.
Published: August 2017

The forthcoming decrease in availability of known, presently economical deposits of crude oil in the foreseeable future, makes it imperative that the search for new oil deposits be intensified and the present methods of oil recovery be improved or new ones introduced. From the work reported in the literature it is obvious that microbiology may play a significant role in both cases. Among many parameters influencing oil recovery, viscosity of the oil and the surface tension between the rock, oil and water are of great importance. Microorganisms growing in the reservoir produce gases and surfactants, which may, to some extent, regenerate the endogenous energy of the reservoir and facilitate movement of the crude oil to the well. The composition of the crude oil may become altered by biodegradation of asphaltic, napthenic and/or paraffinic components of the oil. The fraction being biodegraded varies according to the microbiological population present. In general terms mixed populations are more effective in biodegradative processes and production of surfactants. A combination of sewage microorganisms and reservoir microorganisms adapted to 95°C and high pressure, was found satisfactory. Molasses is a suitable supplementary substrate for the growth of such a mixed population. A decrease of viscosity of oil, resulting from biological degradation, may be a composite effect of degradation of highly polymerised hydrocarbons, precipitation of asphaltenes and solution of biologically produced gases in the oil. Such biogenic gases dissolved in the reservoir water may, in combination with biologically produced acids, contribute to the slow solution of the sedimentary rock, thus increasing the rock's permeability and facilitating migration of the oil through the reservoir.The biological activity in the reservoir is influenced by a number of parameters (pH, Eh, temperature, pressure, oil-water dispersion, mineralisation). The permeability of the reservoir rock is of primary importance. Rocks of permeability less than 150 md are not suitable for biologically enhanced recovery. Field tests indicate that biological activity in a reservoir may result in a drop of 50 per cent in the oil viscosity, a three-fold increase of oil production over several months, increase in water acidity and additional production of gas with a recorded pressure increase from 2 atm to 27 atm. The area affected by the biological activity depends on the mineralogy and permeability of the reservoir rock, sandstone and limestone of permeability higher than 600 md being most suitable.Further properly controlled and documented laboratory and field experiments are urgently required before the feasibility of microbiologically enhanced oil recovery can be firmly established.
RISING COSTS IN AUSTRALIAN HYDROCARBON EXPLORATION AND DEVELOPMENT
Authors: McMinn D.
Published: August 2017

Rapidly rising costs have created operating and investment problems for companies involved in the Australian hydrocarbon resource industry. Expenditure in this area has declined markedly in constant dollar terms, an adverse trend given Australia's outlook for increasing reliance on imported crude oil in the 1980's.Costs in hydrocarbon exploration appear to have risen in excess of general inflation in the Australian economy. This situation may be attributed to the strong upward movement in wages and equipment costs, and in some cases, the low level of domestic exploration in the mid-1970's.Capital costs for hydrocarbon development and pipeline projects in Australia have also escalated, a trend caused by rising wage levels in project construction and increases in equipment costs. Additional factors such as design alterations, environmental considerations and labour disputes, can also add significantly to costs. Large scale hydrocarbon projects, which have long lead times, are susceptible to inflationary trends.Increasing amounts of funds are required for exploration and development as a result of the rising cost trend. However, difficulty is being experienced in raising funds through capital and equity markets, as well as retained earnings. A key factor in securing adequate funds is profitability, which is largely determined by the State and Federal Governments. For the smaller oil and gas producers, the past profitability record has been inadequate, although the improvement in recent years should continue because of higher oil and gas prices.Costs may be expected to continue to increase in hydrocarbon exploration and development, but probably at a lower rate than experienced in the mid- 1970's. The future viability of the hydrocarbon sector is dependent on a favourable investment environment and higher profitability to offset the considerable risks in exploration and escalation in costs.
THE DEVONIAN GREAT BARRIER REEF OF THE CANNING BASIN, WESTERN AUSTRALIA
Authors: Playford Phillip E.
Published: August 2017

A remarkable example of an exhumed Middle to Late Devonian barrier-reef belt extends for about 350 km along the northern margin of the Canning basin in Western Australia. The reefs form a series of rugged limestone ranges cut by deep river gorges which provide spectacular sections through the reefs and associated facies. The gross morphology of the ranges and intervening valleys closely resembles that of the Devonian seafloor, so that from the air the reefs are displayed much as they were in Devonian time.The Canning basin reef complexes offer exceptional opportunities for carbonate research because of the excellence of exposures and the wide variety of facies represented; moreover the rocks are little deformed, are not dolomitized extensively and are unmetamorphosed. Some facies have undergone significant compaction through stylolitization; however, most structures and textures in the limestones can be shown to have had depositional or early diagenetic origins.The reef complexes developed as reef-fringed limestone platforms flanked by marginal-slope and basin deposits. They were built by stromatoporoids, algae, and corals in the Givetian and Frasnian and by algae in the Famennian. The platform and basin facies were laid down nearly horizontally, whereas the marginal-slope facies accumulated with steep depositional dips away from the platform. Marginal slopes commonly were as high as 35° in loose talus and were up to vertical where algal binding occurred in association with early lithification. Geopetal fabrics quantify depositional and tectonic/compactional components of observed dips for paleobathymetric studies of the complexes and their fossil biotas.Four main types of platform margin are present: retreating, back-stepping, upright and advancing. The advancing type is characteristic of the Famennian platforms, whereas the other three are typical of the Frasnian. Pinnacle reefs developed during periods of rapid subsidence, especially during the middle Frasnian, are associated with back-stepping and retreating platform margins.Very early submarine cementation was widespread around the platform margins and on parts of the marginal slopes, but it was not generally extensive in the platform interiors. Early fracturing of reef limestones along the platform margins, probably associated with earthquakes, resulted in the development of neptunian dikes and the collapse of some sections of the reef as submarine rockfalls. These often initiated massive debris flows, many of which carved channels in and, somewhat deformed, the underlying marginal-slope deposits.
RECENT SEISMIC STUDIES UPGRADE THE PETROLEUM PROSPECTS OF THE TOKO SYNCLINE, GEORGINA BASIN
Authors: Harrison P.L.
Published: August 2017

The Georgina Basin covers an area of 325,000 sq km in the Northern Territory and Queensland. Most of the basin contains less than 500m of Palaeozoic sediments, but the Toko Syncline, in Queensland, contains up to 5000m of Middle Cambrian to Middle Ordovician shallow marine carbonate, sandstone and shale. The syncline is bounded on its western margin by the Toomba-Craigie Fault systemHydrocarbon shows are known within the Middle Cambrian to Middle Ordovician strata and some of the rocks have fair source rock potential. Potential reservoir rocks are vuggy dolostones and sandstone. Ordovician siltstones and shales may provide cap-rocks. The southern, deepest part of the syncline appears to have been protected from flushing. AOD Ethabuka-I well, drilled in the southern part, encountered gas in the Ordovician, but drilling problems prevented penetration of the deeper section.A Bureau of Mineral Resources (BMR) seismic survey in 1977, linked lines shot on earlier surveys, tied to wells and examined the Toomba Fault system. The results show that two previously unidentified reflectors represent the top of Upper Cambrian Georgina Limestone and the base of the Middle Cambrian section. Substantial thickening of Ordovician and slight thinning of Middle and Upper Cambrian strata occurs southeast along the axis of the syncline. Southeast progradation of some Middle Cambrian strata and possible bioherms were observed. The Toomba Fault is a high-angle reverse fault and several possible anticlines are present in the adjacent folded and faulted zone. The two largest ones, the Ethabuka and Mirrica Structures, were partially outlined by Alliance Oil Development (AOD). They are shown to lie within a larger structure which has a minimum vertical closure of 700m over a minimum area of 130 sq km. Possible stratigraphic traps are located on the northeastern flank and along the axis of the syncline.The seismic work has better defined the prospective section and confirmed closure on a large structure. The next step in exploration should be to drill the Mirrica-Ethabuka Structure, where about 1500m of section remains to be tested.
DEPOSITIONAL HISTORY OF THE UPPER CRETACEOUS OF THE NORTHWEST SHELF, BASED UPON FORAMINIFERA
Authors: Apthorpe M.C.
Published: August 2017

The palaeogeography of the marine Upper Cretaceous sequences of the Northwest Shelf of Australia has been interpreted mainly from quantitative studies of the fossil foraminifera in the sediments. Due to the distribution of wells, the Dampier and Browse Basins are the areas mainly discussed.The Dampier Basin Upper Cretaceous sequence began with deposition of relatively deepwater carbonates, following a late Aptian-early Albian hiatus. The moderate incline of the basin floor was accentuated by westerly tilting of the basin, probably in the early Turonian. At this time a condensed carbonate facies, indicative of the deepest water interval present within the basin sequence, formed in the western part. The eastern edge of the basin rose above sea level at this time. Sedimentation of carbonates in the western basin was terminated at the end of the Santonian by a regional regression. Clastic shelf sediments covered much of the area throughout the Campanian and Lower Maestrichtian during this regression. In the Upper Maestrichtian, a transgression then resulted in renewed deposition of calcareous sediments over most of the basin.Uninterrupted sedimentation occurred in the Browse Basin from Aptian into Albian times. A gentle basin slope resulted in the development of a very wide shelf zone which received fine clastics throughout Albian and early Cenomanian time. In the early Cenomanian the western part of the basin underwent a progressive tilting into slope water depths, and the facies changed rapidly from clastics to carbonates. It is interpreted that the central and eastern sections of the basin rose above sea level, due to this basin tilting. Transgressive inundation of this exposed land surface commenced in the Lower Santonian. Owing to its shallower character, the regional Campanian regression affected the eastern Browse Basin more strongly than the remainder of the Northwest Shelf, and the area was entirely infilled before the end of the Cretaceous.Differences in the sequences between these two basins are largely due to the initial basin gradient (high in the Dampier Basin and low in the Browse Basin), which had a profound effect on the facies developed. There are, however, other differences in the timing of events, due to local tectonic movement.
PETROLOGICAL AND PETROPHYSICAL STUDY OF PERMIAN ARENITES FOR POTENTIAL SUBSURFACE STORAGE OF NATURAL GAS, SYDNEY BASIN, NEW SOUTH WALES, AUSTRALIA
Authors: Ozimic S.
Published: August 2017

The expanding natural gas market in New South Wales during the next decades will require guaranteed back-up supplies in the event of insufficient deliverability through the Moomba-Sydney pipeline and/or cut-off of the pipeline. Subsurface storage of natural gas in natural reservoirs near the market area offers one solution for ensuring continuity of supply to this market.A petrological, wireline log, structural and reservoir-engineering study has been conducted of water-bearing arenites of the Permian Nowra Sandstone, Muree Sandstone and Snapper Point Formation in the Sydney Basin. This has resulted in the delineation of seven potential natural gas storage reservoirs near Sydney.The cap-rocks to the seven reservoirs are Permian impermeable arenites, siltstone, claystone and shale beds of the Berry Formation, Mulbring Siltstone, Wandrawandian Siltstone and Snapper Point Formation.Porosity in the Nowra and Muree Sandstone ranges from 5.5 to 12.2 percent and in the Snapper Point Formation from 5.4 to 6.8 per cent. Permeability is estimated to range from 0.47 to 5.00 millidarcies.The structures of these potential reservoirs include both faulted and unfaulted, gently folded anticlines, and an irregular dome. Their areal extent and vertical closure range from 1 to 45 sq km and 20 to 225 respectively.Total potential storage capacity for the seven reservoirs is estimated to be 21.3 x 109m3 of natural gas, and their deliverability potential, based on permeabilities of 1.0 and 5.0 millidarcies, ranges from 0.002 to 0.103 x 106m3 of natural gas per day per well.
DIELECTRIC CONSTANT LOGGING A PROGRESS REPORT
Authors: II W.R. Berry , Head M.P. , Mougne M.L.
Published: August 2017

The recent evolution of equipment capable of measuring the relative dielectric constant of a formation has stimulated new approaches to the evaluation of water saturation. In many oil productive reservoirs, the formation water resistivities are either unknown or are very high; thus complicating conventional resistivity dependent solutions for water saturation.By determining the relative dielectric constant of the formation and through application of the Lichtnecker and Rother equation for the dielectric constant of mixtures, the analyst may identify the presence of hydrocarbons and in many cases, quantify reserves. Additionally, a quick look overlay technique for qualitative evaluation can be utilized. These procedures can be of great help in both exploration and development environments where conventional methods have led to confusion.
DEEPWATER DRILLING AND PRODUCTION SYSTEMS OVERVIEW
Authors: McKinney J. M.
Published: August 2017

The petroleum industry is now involved in a highly significant exploration program to define the hydrocarbon potential of deepwater sedimentary basins. Within the last year, the ability to drill in waters deeper than 1300m has been demonstrated, and exploration plans for water depths down to 1600m have been announced. This paper reviews the industry's deepwater drilling experience and describes some of the unique technology required for a successful deepwater drilling venture. Drilling in over 1000m of water calls for more sophisticated, higher strength system components than are needed in shallower waters. Some of the differences between deepwater drilling procedures and more conventional shallow water techniques involve vessel carrying capacity, the use of a dynamic positioning system for staying on location, riser buoyancy materials, improved riser components and a multiplex electrohydraulic blowout preventer control system.Progress has also been made in developing production systems for use in water depths greater than 300m. The guyed tower concept, a product of Exxon's developmental work, has been demonstrated to be a cost-effective alternative to fixed-bottom platforms. The caisson vessel, designed to accommodate both drilling and production activities and to minimize motion caused by rough sea conditions, is an attractive option for operations in deep water. In addition, experience with a prototype of Exxon's subsea production system has demonstrated that this system is also ready for commercial use.
PROCESSING THE LOAN PROPOSAL FROM REQUEST TO DRAWDOWN
Authors: Dunn P.C. , Palethorpe N.J.
Published: August 2017

When natural resource companies request loan funds, many steps are involved in processing the proposal. Although circumstances differ with the size and type of venture, there are basic stages, some of which commonly cause unexpected delays.The bank typically expresses interest in assisting the company on a non-commitment basis. An appraisal of reserves, capital expenditure, operating assumptions, marketing, management and other factors can then proceed along with the company's project planning. When the total sum required is crystallised and a firm request for a loan is made, the following are some of the procedures required before the first drawdown can be effected.The equity/loan ratio, the mix of funds (term loan, refinance loan, leasing, bills, overdraft, etc.) and the currencies appropriate to the project are discussed. The bank must be satisfied that approvals by government and other authorities have been obtained or are probable to allow the project to proceed. An essential part of this appraisal is an examination of all financial forecasts and, if necessary, the preparation of additional sensitivity analyses. A submission is then prepared for presentation to the bank for approval. This may be granted subject to certain conditions including completion of an appropriate loan agreement incorporating the terms broadly agreed.The Company is advised, then bank lawyers normally draw up the loan agreement documentation and company's lawyers review and discuss. The agreement is signed and stamped and the first drawdown can then be made.
LEGAL CONTROLS OVER PETROLEUM EXPLORATION AND DEVELOPMENT OFFSHORE WESTERN AUSTRALIA
Authors: Thompson A.G.
Published: August 2017

Increased petroleum exploration and development activities offshore Western Australia will continue to attract the focus of many companies, contractors and investors who will find that their exploration and development activities and operating practices are controlled by a mixed regime of State and Federal legislation. This mixed regime has its sources in international and constitutional law.Working within these controls is not assisted by the complexity of State and Commonwealth jurisdictional problems in respect to offshore areas. Certain governmental arrangements between the State and the Commonwealth, however, facilitate continued exploration activity offshore, whilst some of the legal issues remain to be resolved. Some guiding principles as to what laws apply offshore and to what extent, are indicated.The consultative arrangements between the State and the Commonwealth under the Offshore Petroleum Code allow for Commonwealth ownership and State control of offshore petroleum resources to co-exist. These are commented upon and the Petroleum (Submerged Lands) Acts are analysed with respect to the nature and security of petroleum titles; the setting, performance and variation of work and monetary obligations; the range of administrative discretion in relation thereto; the transferability of petroleum interests and the rate and calculation of royalties.Directions regulating offshore operations generally and covering exploration, reporting, platforms, pipelines, production and work practices are explained. Some of the environmental controls are also mentioned.
EVOLUTION OF SEISMIC TECHNOLOGY INTO THE 1980's
Authors: Graebner R.J. , Wason G. Steel and. C.B.
Published: August 2017

In the last few years, the quality and resolution of subsurface images, based on seismic data, have improved considerably with the introduction of wavelet processing and three-dimensional (3D) seismic techniques. Together, these are being used increasingly in field development to optimize drilling locations and improve estimates of hydrocarbon reserves.Exploiting the steady gains in computer performance, significant enhancement in image resolution is being achieved using the convolutional model of seismic wave propagation. In the 1980's, progress will proceed apace along this path, one which is analogous to the photographic imaging technique; furthermore the wavelet processing techniques will continue to improve, aided by better imaging methods based on holographic principles.Another innovation that will offer the potential for a more accurate estimation of hydrocarbon reserves is the application of inversion by modelling. These methods generate estimates of the subsurface lithologic parameters directly from the data. The results are reconciled with available borehole logs and used to define reservoir characteristics at the spatial sampling of the data.
WARROON GAS DISCOVERY SUPPORTS EXPLORATION OF ANTICLINES
Authors: BROWN B. R.
Published: August 2017

Warroon, a small gas condensate discovery in the western Surat Shelf, was mapped as a faulted anticline from seismic data shot in April 1979. The discovery well was drilled in August 1979 on the then highest known point of the mapped closure. The well flowed up to 8 MMcf/D from about 2.4 m (eight feet) of Showgrounds Sandstone over the gross interval 2 048 to 2 060 m (6 720 to 6 760 ft). Subsequently, two small seismic surveys comprising 62 km and including experimental shooting and acoustic impedance processing have been shot over the anticline. A step-out will be considered in the 1981 drilling program.The discovery of gas and condensate in Warroon, and in the Glen Fosslyn discovery in an adjacent permit, optimistically suggests that the prospective area of the Wunger Ridge may be extended. A major seismic survey comprising over 450 km of 12-fold 96 channel recording was shot in the Spring of 1980. The interpretation of the data could lead to proposals to drill a number of wildcats on structures similar in appearance to Warroon.
ENGINEERS AND BANKS: THEIR ROLES IN ENERGY FINANCING
Authors: Wright W. G. , Cleland N. A. , Edgington A. N.
Published: August 2017

Since 1928, banks in North America have been providing funds for oil, gas and other energy projects, secured by income from future production. Over the years, the types of lending and the limits set have changed as legislation has changed and technical knowledge has expanded.Banks can only lend money if there is a high degree of certainty that both the principles and interest can be repaid over the loan period. Engineers are required to prepare objective opinions of future cash flows, which are then used by the banks' engineers to establish loan limits. As technical capability has expanded, the banks have increased the risks they would accept when lending against future energy production. No longer must proven reserves be producing—but they must still be proven.With the emergence of major capital-intensive projects requiring massive front-end investments before developing any cash flows, innovative new financing methods were required to provide debt capital. These methods evolved in financing projects in Alaska and the North Sea and are now available for energy financing around the world.As lenders have accepted higher levels of risk for these major projects, they have come to depend more and more on the engineering assessment of the project, as opposed to the balance sheet strength of the borrower.
AN ASSESSMENT OF THE PETROLEUM PROSPECTS FOR THE GALILEE BASIN, QUEENSLAND
Authors: Jackson K. S. , Horvath Z. , Hawkins P. J.
Published: August 2017

The Galilee Basin in central Queensland is an extensive intracratonic basin containing up to 2 800 m of Late Carboniferous to Middle Triassic strata deposited under predominantly fluviatile conditions in two depocentres, the Lovelle Depression and the Koburra Trough.The exploration criteria of petroleum geochemistry, reservoir rock quality, structural and trapping style have been assessed.The source potential is generally poor with the Aramac Coal Measures, basal Jericho Formation, and the underlying Devonian rating best for possible hydrocarbon generation. Organic maturation is generally not reached until the Late Carboniferous Jochus Formation. The predominant organic maceral type for the Late Carboniferous and the Permian is vitrinite, suggesting gas-prone source.The potential for reservoir rock is best developed in the Aramac Coal Measures and Colinlea Sandstone correlative units within a fluvial channel sandstone facies. Structural and stratigraphic traps formed in the Late Carboniferous and the Early Permian are thought to be most prospective. The presence of oil and gas in ENL Lake Galilee 1 does imply that hydrocarbons have been generated in the basin or possibly from the underlying Devonian. The application of oil/source rock correlation data suggests the basal Jericho Formation or the underlying Devonian as the oil source. The Aramac Coal Measures, with a combination of reservoir and source facies even though only marginally mature, are thought to offer the best play.Lack of success to date may well reflect deficiencies in one or more of the exploration criteria. However, examination of drilling locations suggests that many wells were poorly sited owing to the difficulty in seismic mapping below the Late Permian coal seams.
GORGON 1 - SOUTHERNMOST RANKIN PLATFORM GAS DISCOVERY
Authors: Campbell I. R. , Smith D. N.
Published: August 2017

The Gorgon 1 gas discovery is located on the western margin of the Barrow Sub-basin in the Carnarvon Basin of Western Australia. The well was drilled by West Australian Petroleum Pty Limited (WAPET) in late 1980 on the southern extremity of the Rankin Platform. The location is 72 km west-northwest of Barrow Island and the water depth is 259 m. The first discovery on the Rankin Platform was made in 1971 by the Burmah Oil Company of Australia (BOCAL), now Woodside Offshore Petroleum Pty Ltd. Since 1971, both WAPET and Woodside have made several gas/condensate discoveries to the northeast of Gorgon.The Gorgon structure consists of an elongate, uplifted, fault-bounded block of Triassic sediments about 5 km wide and 35 km long and oriented approximately north-south. The southern limit of the block is defined by the convergence of the bounding faults on the east and west sides of the structure.The reservoir section, as in West Tryal Rocks and other Rankin Platform accumulations, consists of Late Triassic fluviatile and deltaic sands in a sequence known as the Mungaroo Formation. Secondary and shallower objectives in Gorgon 1 were reservoirs in the deltaic Flacourt and Malouet Formations of the Barrow Group. These were mapped in a dip-closed, faulted anticline at the Neocomian unconformity which is overlain by the widespread Muderong Shale.The primary source of the hydrocarbons is believed to be the thick sequence of Late Jurassic shales (Dingo Claystone) in the Barrow Sub-basin to the east of the Gorgon Structure.Gorgon 1 was drilled to a depth of 4401 m and encountered massive, fluvio-deltaic sandstone bodies within a gas column of 409 m in the Late Triassic Mungaroo Formation. Six drill stem tests were conducted over selected intervals within the Mungaroo Formation. These produced flow rates of up to 770 500 m3 of gas per day and 2.5 kl of condensate per day at a surface flowing pressure of 16 300 kPa on 2 X 13 mm surface chokes. A seventh drill stem test conducted in the Malouet Formation produced a flow rate of 267 700 m3 of gas per day and 23.3 kl of condensate per day at a surface flowing pressure of 10 500 kPa on a 1 X 13 mm surface choke.The reservoir sands in the Mungaroo Formation are medium to coarse grained and have an average porosity of 12 per cent and a permeability range of 0.1 to 527 millidarcies.
FOUR NEW BASS STRAIT PLATFORMS — A PROJECT MANAGER S VIEW
Authors: Power J. W.
Published: August 2017

The offshore development by Esso/BHP of the West Kingfish, Cobia, Fortescue and Flounder oil fields in the Gippsland Basin is one of the significant undertakings by the petroleum industry during the 1980s. Production from the fields will help sustain the current level of production from Bass Strait into the latter part of this decade.This paper examines some of the principal project management issues and actions involved in the planning and execution of the design and construction phases of the platforms and pipelines associated with each of these fields.
DEEP TECTONIC FOUNDATIONS OF THE EROMANGA BASIN
Authors: O'Driscoll E.S.T.
Published: August 2017

The Eromanga Basin in eastern Australia is underpinned by major regional tectonic features which extend into it from adjacent basins and from the surrounding frame of older bedrock and basement. Their recognition and resolution require the integration of special treatments of gravimetric, magnetic and strato-structural data.The features are major pattern discontinuities, generally strongly linear, and are part of a continental pattern. They are extensions of the same systems of major transcontinental tectonic trends which pass through and under surrounding orogenic centres, such as the Adelaide, Mount Isa, New England and Lachlan Geosynclines, the Arunta and Musgrave Blocks and the Georgetown Province. They are regional loci variously of intensified folding, faulting and fracture, and of anomalous heat flow gradients.Their association with different ages of metallogenesis, and their repeated correspondence to lithologic and stratigraphic patterns, indicate that they are primary crustal features which have been tectonically active through most of geologic history, controlling gross basin morphology as well as more detailed distributions of particular sedimentary facies.Their conjunctions show a spatial relationship to known petroleum deposits, suggesting that they fulfil a dynamic and thermal role in petroleum generation and accumulation. They provide an essential frame of reference for the recognition and development of more finely-tuned structural patterns which act as pathfinders in petroleum exploration.
THE TUNA FIELD, A RECENT GIPPSLAND DEVELOPMENT
Authors: O'Byrne M. J. , Henderson D. J.
Published: August 2017

The Tuna field, 42 km offshore from the Victorian coast, was contributing approximately four percent of Australia's total crude oil production by the time development was successfully completed in 1982. The field was the most complex of the seven Gippsland Basin fields developed by the Esso/BHP joint venture up to that time. Commercial reserves are contained in four sets of reservoirs, featuring both structural and stratigraphic traps.The field has been developed with an 18 well platform, initially as an oil producer and later to be converted for gas production. Development drilling commenced in October 1978, with production start-up 11 months later when the first four wells were brought on-line. Several oil accumulations were discovered during development drilling. Two of the development wells were used also as deep exploration wells, requiring the drilling of "S" shaped wells.The complexity of the reservoirs was revealed during simultaneous drilling and production operations. Crucial reservoir production performance data were obtained sufficiently early for optimum well targetting and completions. Reservoir pressure profiles, collected using the Repeat Formation Tester (RFT)*, and the performance of producing wells showed that the major oil reservoir was far more complex than the original exploration wells had indicated. This, plus the additional discoveries, led to the installation of 13 multiple completions, including one dual/tandem completion. Development drilling was completed in March, 1982. Satisfactory development of the field was greatly assisted by extensive performance monitoring during development.
HYDROCARBON GENERATION IN THE NORTHERN PERTH BASIN
Authors: Thomas B. M. , Brown S. A.
Published: August 2017

All known commercial hydrocarbon accumulatios in the Perth Basin, Western Australia, occur within the Dandaragan Trough or along its flanks. Land plant-rich source rocks are widely distributed throughout the Permian, Triassic and Jurassic sections of the basin. Hydrocarbon accumulations are mainly dry gas and gas/condensate, although secondary occurrences of light, waxy oil are also of economic significance. The Lower Jurassic Cattamarra Coal Measures provide both source and reservoir for gas/condensate accumulations in the central Dandaragan Trough (Walyering, Gingin). Gas at Dongara, Mondarra, Yardarino and the more recent discovery, Woodada, may have been generated from both the Lower Triassic and Permian, although there is some evidence that the Permian is the principal source. The associated thin oil legs encountered in parts of these fields and at Mt Horner is attributed to the oil-prone basal Kockatea Shale (Lower Triassic). Regional studies indicate a Neocomian uplift of the western flank of the Dandaragan Trough, centred on the Beagle Ridge. Vitrinite reflectance data suggest that the uplift and erosion of the Beagle Ridge was accompanied by higher geothermal gradients, up to 7.5°C/100 m in the Neocomian. Modern gradients of up to 5.0°C/100 m have been measured on the Beagle Ridge and possibly represent this waning geothermal anomaly. In contrast, low geothermal gradients are found in the Dandaragan Trough (around 2.5°C/100 m), and hydrocarbon generation presently occurs at great depths where sandstone reservoir properties are often inadequate for commercial production.
YARDIE EAST—1: A DIRECTIONALLY DRILLED WILDCAT
Authors: Tomlin G. F. , White H. W. , Dumbrell R.
Published: August 2017

Under the terms of a farmout agreement a well to 4200 metres true vertical depth was required to test an offshore structure in the Indian Ocean 3.4 kilometres from the Cape Range landfall. Western Australia.Due to the structure being located in an offshore environmentally sensitive area and the proximity of the structure to the Ningaloo Reef, the decision was taken by the consortium to drill a directionally controlled wildcat well, Yardie East-1, from the nearest landfall point, in a designated National Park.With the co-operation of the regulatory authorities a drilling plan was approved which entailed a critical analysis and modifications to the drilling rig, Rig No. 15 contracted from Oil Drilling and Exploration Limited, to satisfy the loads associated with a directionally drilled well to a worst condition programmed measured depth of 5650 m.Utilising modern technology the wildcat well was drilled to the target at the top of the structure at 5110 m at a penetration angle of 50° and an azimuth of 308° in 142 days from spud.Earning conditions were satisfied with an eventual total drilled depth of 5593 m. Logging and an open hole drill stem test were conducted prior to abandoning the well 186 days after spud.It is believed that Yardie East-1 is the longest well, in terms of measured depth, drilled onshore or offshore Australia.
EARLY PRODUCTION THROUGH USE OF SUBSEA TEMPLATE DRILLING AND PRODUCTION STRING TIE-BACK
Authors: Gulikers H. , Wetch S. , Griffith D.
Published: August 2017

The development of offshore fields using subsea drilling templates and tie-back equipment has become an accepted means of achieving early production.Using subsea templates for cluster drilling permits drilling development wells while platform and production facilities are being constructed. Therefore development drilling need not wait for platform installation. Accelerated development drilling means that production can begin very soon after the platform is installed over the subsea template wells.Necessary equipment includes subsea templates, subsea drilling equipment, jacket guidance equipment, and tie-back adaptors to the subsea wellhead housings and casing hangers.Three types of subsea templates used today are unitized, modular and spacer templates. Selection of the template is mainly dictated by water depth and number of wells.
IMPLICATIONS OF FOREIGN INVESTMENT POLICY FOR PETROLEUM DEVELOPMENT IN AUSTRALIA
Authors: Horton-Stephens K. J.
Published: August 2017

In recent years the proportion of petroleum exploration outlays made by Australian investors has risen significantly, though this trend may now be receiving a setback owing to the recession.Budgeted exploration outlays for 1981 by foreign interests and naturalised and naturalising companies accounted for 59 percent of total expected petroleum exploration outlays. In comparison, the foreign participation rate was 57 percent in 1980, 72 percent in 1979, and 74 percent in 1978.There has been some comment that, because of the difficulties Australian explorers face raising capital under present sharemarket conditions, a rise in foreign participation in Australian petroleum resources could result. It has been suggested this could destroy community acceptance of foreign investment which could rebound on future investment levels. It is claimed that lower Australian participation in exploration would also result in Australians being required to pay a higher entry price to ventures later and that rigid insistence on the Government's Australian equity guidelines being met at development could slow the pace of resource development down to what Australians can afford to pay for.There can be problems from time to time in mobilising sufficient risk capital to maintain levels of exploration activity in Australia. Yet there seems little merit in trying to predict a long-run trend in foreign/Australian participation from a short-term relationship between foreign and domestic investment.Foreign investment plays a significant role in the petroleum industry. The Government's foreign investment policy aims to maximise the benefits from this investment while providing adequate opportunities for Australian participation.
A PROJECT OF TECHNOLOGY TRANSFER TO THE CHINESE OFFSHORE PETROLEUM INDUSTRY
Authors: Hart Geoffrey
Published: August 2017

Under the umbrella of a Technical Co-operation Agreement between Australia and China, CSR is managing a project to transfer to the Chinese petroleum industry the equipment and knowledge required for the financial evaluation of large offshore developments by computer modelling.A medium-size interactive computer will be supplied along with a financial evaluation software package. Australian specialists in financial evaluation and modelling, computer management and offshore engineering will visit China to conduct training courses, and twelve Chinese professionals will visit Australia for tertiary studies and work experience.China is coming to the end of the first round of awarding contracts to foreign companies for the exploration of offshore oil fields. Ahead are later stages of bidding and contract negotiation, the evaluation of field development proposals, and the management of joint venture participation in producing fields. The computer equipment and application skills to be supplied under this project will significantly upgrade the capability of the Chinese petroleum industry to manage these future stages.