bluuebunny/crossref_metadata_2025 huggingface dataset:
PETROLEUM EXPLORATION PREVIEW FOR 1967
Authors: Condon M. A.
Published: August 2017

Exploration for petroleum in Australia paused in 1966 and this pause is likely to continue in 1967.The number of wells drilled and seismic activity will both be slightly less in 1967 than in 1966, but the work will generally be directed to more specific targets. The cost of exploration will be somewhat higher than in 1966.During the year off-shore drilling should increase and it is expected that five mobile rigs will be drilling in the offshore areas by the end of the year. The immediate structural targets available for these rigs are in the Gippsland, Bass and Otway Basins (Victoria-Tasmania), the North-West Shelf and Timor Sea-Bonaparte Gulf, and in the Gulf of Papua.Onshore exploration will be concentrated in the western Australian basins, the Surat Basin, the central Great Artesian Basin, and the Gidgealpa region of the southwestern Great Artesian Basin.The success or otherwise of the off-shore drilling will determine the rate of exploration over the next few years. If important discoveries are made off-shore, these may and probably would result in more intensive exploration of the same stratigraphic intervals onshore.The exploration patterns of Australia and several other countries before and after first commercial discovery are compared. This indicates that Australian discovery came early, as compared with other countries, where production has developed since the war, but that post-discovery effort in Australia has been very much less. The main obvious differences appear to be that in Australia the average size of the exploration concession is very much larger and the number of operators (having regard to the areas concerned) is much smaller, than in the other successful countries.There has been a gradual movement towards reducing the size of operating areas in Australia either by obligatory relinquihment or by farmout, but if discoveries are to be made at a satisfactory rate more operators are needed in every basin.The economic environment of Australia vis-a-vis Middle East oil and oil markets is probably the main basic reason for the peculiar exploratory pattern, which has impelled the Government to provide financial incentives to encourage exploration and development.
WOOLNOUGH HILLS AND MADLEY DIAPIRIC STRUCTURES, GIBSON DESERT W.A.
Authors: Wilson R. B.
Published: August 2017

A diapiric origin is indicated for several domal structures with arcuately linear trends, in the western Gibson Desert, Western Australia. The most prominent of these trends is approximately latitudinal, although a minor trend north of Woodnough Hills, is north to northeasterly.Foundered blocks of Upper Proterozoic, Permian and possibly Jurassic sediments occur within the gypsum-cores of several of the diapirs. The sharp angular unconformities between Upper Proterozoic and Permian and Permian and Jurassic sediments respectively, suggests that diapiric uplift and piercement has continued, at least intermittently, for extensive periods of geologic time. Gentle doming of the late-Tertiary laterite surface evidences the continuation of diapiric uplift into post-Tertiary times.
THE TECTONIC ELEMENTS OF THE PERTH BASIN
Authors: Jones D.K. , Pearson G.R.
Published: August 2017

Birth and growth of the highly faulted Perth Basin was dominated by the Darling Fault which down-throws an essentially elongate sedimentary trough against a Precambrian Shield to the east. The Precambrian Northampton and Leeuwin Blocks restrict the basin to the north and the south. The Perth Basin embraces four major sub- basins separated by intra-basin uplifts. These sub-basins are the Dandaragan and Sunbury Troughs and the Abrolhos and Vlaming Sub-basins. Major intra-basin uplifts include the Beagle, Turtle Dove and Harvey Ridges, and the Edwards Island Block.Surface outcrop is representative of only a small part of the total stratigraphic column. Deposition of Ordovician - Silurian sediments in only the extreme north of the basin was followed by a long period of non-deposition. Sedimentation recommenced in the Lower Permian and continued with minor breaks throughout the Mesozoic and into the Tertiary. The Permian had a widespread distribution, as did the Triassic and Jurassic which attained maximum thickness in the Dandaragan Trough. A major intra-Neocomian unconformity developed in the Vlaming Sub-basin where up to 20,000 ft. of pre-unconformity Neocomian and 5,000 ft. of post-unconformity marine Cretaceous sediments were deposited. Tertiary sediments were deposited in both the Vlaming and Abrolhos Sub-basins.Limited movement on the Darling Fault in Permian and Lower Triassic times led to gentle basin downwarp. Renewed fault activity in the Upper Triassic resulted in rapid basin subsidence, and less violent fault activity continued through the Lower Jurassic. The most severe tectonic activity and basin subsidence, with local uplift, occurred in the Upper Jurassic and Neocomian, at which time graben-collapse of a mid-basin arch offshore from Perth formed the Rottnest Trench. This intra-Neocomian tectonism was probably associated with .sea floor spreading, the westerly drift of India from Australia, and the break up of Gondwanaland.This structural synthesis of the Perth Basin is largely derived from geophysical surveys and deep drilling carried out over the past twenty-three years on the present leases of West Australian Petroleum Pty. Limited (WAPET).
RELATIONSHIP BETWEEN THE ADAVALE AND DRUMMOND BASINS
Authors: Vine Ralph R.
Published: August 2017

The main Drummond Basin and Adavale Basin sequences are of different ages. Devonian sediments that were deposited contemporaneously with the Adavale Group occur directly below the Permo-Triassic Galilee Basin sequence in Lake Galilee No. 1 well and also occur as erosional remnants below the predominantly Lower Carboniferous Drummond Group in the Drummond Basin area The w item limit of the Drummond Group is a lineament, the Belyando Feature comprising fault induced monoclines and fracture zones, and marked by linear steep gravity gradients and basalt vents. This lineament may be a major basement fracture which determined the western margin of the Drummond Basin. The Drummond Basin could then be interpreted as an. intermontane trough formed after development of the Adavale Basin had been completed.
D/V GLOMAR CHALLENGER AND THE DEEP SEA DRILLING PROJECT
Authors: Peterson M.N.A. , Turrentine R.E.
Published: August 2017

The unique dynamically positioned drilling vessel Glomar Challenger, which made its scheduled port call at Darwin, Australia in early January, and is now operating in the Indian Ocean, has successfully accomplished drilling and coring of deep ocean sediments for more than three and one -half years. Approximately 340 holes at 225 sites have been drilled in water depths to 20,316 ft., and with a maximum single penetration of 3,888 ft. into the oceanic floor. Less than 1% breakdown time has been experienced. Re-entry capability has been developed and used. Calculated to the end of Leg 20, accounting for about 40 months of operations, the Deep Sea Drilling Project has established an impressive record: a total of 279,848 ft. of rock penetration, 88,849 ft. of attempted coring and 52,052 ft. of recovered core.Scientific information recovered and its interpretation bear on many aspects of geology and geophysics, including: the new global tectonics, interpretation of seismic reflection and refraction profiles, variations in oceanic chemistry and the history of oceanic current systems, plankton biostratigraphy, the nature and composition of oceanic sediments and economic potential, chemical changes to sediments after burial, organic evolution and productivity and response to isolation, vertical tectonic motions, activity at and near trench systems and continental margins, and the determination of amount of latitudinal shift of the crust of the earth relative to the rotational co-ordinates of the earth.Plans for the future include an additional three years of drilling, bringing the total time under contract to seven years of uninterrupted work between Global Marine Inc., Scripps Institution of Oceanography, the National Science Foundation (an Agency of the U.S. Federal Government) and the JOIDES consortium of oceanographic institutions. The feasibility of an Antarctic drilling program is being investigated and will be undertaken insofar as possible. Heave compensation and usage of longer drill strings are planned for the future.
GEOLOGY AND GEOPHYSICS IN THE DISCOVERY OF GIANT OIL FIELDS
Authors: Kent P. E
Published: August 2017

The paper gives the case histories of discovery in three major oil field areas-Iran, northern Alaska and the North Sea. These areas differ in their regional features and in the consequent requirements for geological and geophysical investigation and delineation. In Iran the earlier discoveries were based entirely on surface geology; geophysics became important with the need for deep survey. In northern Alaska structures mapped at surface gave only minor shows. Seismic surveys following geological deductions on reservoir development led to discovery of the giant Prudhoe Bay field near the Arctic coast. In the North Sea, in the much more complex extension of Permian-Mesozoic basins already well known on land, location of structures has been entirely by seismic survey.There is no close relation between the new Global Tectonics and the location of major oil field belts. The factors controlling the latter are multiple and complex. Resolution of the relative importance of vertical (epeirogenic) displacement as against the effect of lateral plate movement is nevertheless critical, particularly in Alaska.There is at present a large unresolved discrepancy between the times at which some continental margins developed (North Atlantic, East and West Indian Ocean) and with the physical evidence of sea floor spreading. In the three areas quoted, breakdown of the continental margins by vertical movements started in the Permian (—280 million years), but spreading is dated as beginning only in the late Cretaceous (—70 million years). It is the earlier movements, unexplained by current global theories, which have most relevance for petroleum exploration.
SIMPSON DESERT SUB-BASIN—A PROMISING PERMIAN TARGET
Authors: Williams George E.
Published: August 2017

Sediments of three major basins occur in the Simpson Desert region of central Australia:Cambro -Ordovician dolomites and sandstones, and Siluro- Devonian conglomerates, sandstones and shales, related to the Amadeus Basin:Permian conglomerates, sandstones, shales and coals of the Simpson Desert Sub-basin, the extensive eastern lobe of the Pedirka Basin:Mesozoic sandstones and shales of the Eromanga Basin.Principal petroleum exploration interest is presently directed toward the Permian sediments, which have many features in common with the petroleum producing Permian section of the neighbouring Cooper Basin.Lower Permian sediments known from drilling in the Simpson Desert Sub-basin comprise glaciofluvial conglomerates and sandstones overlain by fluvial and lacustrine sandstones, silt-stones, shales and coals. The maximum thickness encountered in wells is 1,479 ft (448 m) in Mokari 1.Recent seismic exploration 50 to 100 mi (80-160 km) west of Poeppel Corner in the deeper part of the Simpson Desert Sub-basin indicates that an additional sediment package up to 1,500 ft (350 m) thick occurs at depths of 6,500 to 7,500 ft (2,000-2,300 m) between Lower Permian and Lower Jurassic sections. This sediment package, nowhere penetrated by drilling, may be Middle to Upper Permian and/or Triassic in age. It is of great significance to petroleum exploration in the sub-basin and substantially upgrades the hydrocarbon prospects of the region.Permian sediments in the Simpson Desert Sub-basin thin by onlap, wedge out and stripping over the crests of anticlinal growth structures. Crestal sediments probably comprise mainly porous sandstones, grading off-structure into thicker sequences containing carbonaceous shales and coals. Such carbonaceous potential source rocks are probably best developed in the deepest part of the sub-basin, where Triassic cap rock may also be present. Two particularly promising drilling targets—the Colson Anticline and the East Colson Anticline—have been revealed by recent geophysical surveys in this portion of the sub-basin. Wells drilled on these structures may intersect Permo-Triassic sediments up to 2,200 + ft (670 in) thick which are comparable in age and type with producing sections in the Cooper Basin.
CENOZOIC PLANKTONIC FORAMINIFERAL ZONATIONS OF SOUTHERN AUSTRALIA AND NEW ZEALAND
Authors: Jenkins D. Graham
Published: August 2017

BIOSTRATIGRAPHIC DOCUMENTATION of fossil species of planktonic foraminifera has played a major role in correlating marine Cenozoic rocks because of their relatively high diversity, abundance, rapid evolution and wide geographic distribution. A major step was undertaken in Trinidad in 1945 with the division of the Oligocene-Miocene rocks into three zones based on planktonic foraminifera and with the intensive oil-search on the island, there began an equally intensive research programme and rapid development in the study.Two research projects, independent of each other, were initiated in Gippsland. Victoria in the 1950s which resulted in publications: (1) from surface samples, a faunal unit system was devised for the Upper Eocene-Miocene. and (2) 11 named planktonic foraminiferal zones were established in a four-foot sampled Oligocene-Miocene sequence of the Lakes Entrance oil shaft. The latter scheme was tested and expanded for 3 years during oil exploration on the East Coast of New Zealand during 1959-1962 and a further four years was spent thoroughly testing, and expanding it into 21 zones sub-dividing the whole Cenozoic time of 67my. The zones can be identified in both surface and sub-surface sections and used for direct, accurate correlations of marine rock sequences thus providing the geologist with essential data for the construction of maps and subsurface control.The zonal scheme was re-exported back to South Australia, later to Gippsland and used there with minor local changes in the off-shore oil exploration; in 1973 the zonal scheme was further tested during the Deep Sea Drilling Project Leg 29 in the area south of New Zealand and Australia.Studies of planktonic foraminifera and allied microfossils has resulted in the cheapest and most reliable method for rapid age determinations of Cenozoic marine rocks; in perspective it plays a minor, but essential role in oil-search. The zonal scheme is a dynamic model subject to change and improvement.
DEFINITION OF PETROLEUM RESERVES USING PROBABILITY ANALYSIS
Authors: McKay B.G. , Taylor N.F.
Published: August 2017

The realistic estimation of reserves and resources is important to many diverse groups including explorers, producers, auditors, taxmen, bankers, shareholders and governments. Reserves data are used in different ways for a variety of reasons and often the figures are used without adequate definition and/or recognition of the uncertainties associated with them. Any calculation method which fails to consider the uncertainties involved, cannot portray a realistic assessment of reserves.Esso Australia Ltd. uses a relatively simple method to generate probability distribution curves in order to allow a more perceptive definition of the range of reserves for the offshore oil and gas fields in the Gippsland Basin and Esso is advocating wider petroleum and mineral industry acceptance of this approach.The method involves defining data distributions for each of the reservoir properties (volume, porosity, water saturation, compressibility and recovery factor) which are multiplied using Monte Carlo Simulation to generate the distribution of reserves. Actual input consists of data from:A high confidence area immediately surrounding well control, where the rock volume is relatively closely defined and the distributions of the other parameters, with the exception of recovery factors, reflect the observed variations.Other areas which are only seismically controlled, where the data ranges reflect both observed and interpreted variations in volume (gross and net), porosity, water saturation, compressibility and recovery factor.The curves generated for each area are then added by Monte Carlo Summation to yield the probability distribution of reserves for the whole field. In this method all available data are used and fewer subjective decisions are necessary. The computer generated distribution curves plot cumulative probability on the y-axis versus reserves on the x-axis. The curves allow the evaluation of the entire range of potential reserves, are valuable in economic and risk assessments and allow for more consistency in defining reserves for reporting purposes. The different categories of reserves, viz. "proved", "probable" or "possible", can be specified from the total field curves at defined probabilities. Moreover, the slope of the cumulative curve provides a direct indication of the level of knowledge of the field or parts of it.
THE FORTESCUE FIELD - NEW OIL IN THE GIPPSLAND BASIN
Authors: Thornton R.C.N. , Burns B.J. , Khurana A.K. , Rigg A.J.
Published: August 2017

The Fortescue-1 well drilled in the Gippsland Basin in June 1978 was a dry hole. However, results of detailed stratigraphic analysis together with seismic data provided sufficient information to predict the possible occurrence of a stratigraphic trap on the flank of the giant Halibut structure.Three months later the West Halibut-1 well encountered oil in the Latrobe Group 16 m below that depth carried as the original oil-water contact for the Halibut field. Following wireline testing in both the water and oil-bearing sandstone units, two separate pressure systems were recognised in the well. Three additional wells, Fortescue-2, 3 and 4, were drilled to define further the limits of the field, the complex stratigraphy and the hydrocarbon contacts.Integration of detailed well log correlations, stratigraphic interpretations and seismic data indicated that the Fortescue reservoirs were a discrete set of units stratigraphically younger and separated from those of Halibut and Cobia Fields. Analysis of pressures confirmed the presence of two separate pressure systems, proving none of the Fortescue reservoirs were being produced from the Halibut platform. Geochemical analysis of oils from both accumulations supported the above results, with indications that no mixing of oils had occurred.Because the Fortescue Field is interpreted as a hydrocarbon accumulation which is completely separated from both Halibut and Cobia Fields, and was not discovered prior to September 17, 1975, it qualified as "new oil" under the Federal Government's existing crude oil pricing policy. In late 1979, the Federal Government notified Esso/BHP that oil produced from the Fortescue Field would be classified as “new oil”.
REVIEW OF METHODS FOR FORECASTING ENERGY BALANCES
Authors: Tormasi T.
Published: August 2017

The level of exploration is influenced by expectations concerning future energy demand and supply balances and prices.It is the task of the forecaster to quantify expectations. The process involves prediction of events both entirely beyond the control and somewhat within the control of the forecaster.Past results of forecast accuracies leave considerable scope for improving methods of prediction.Techniques like scenario and model building are considered helpful in improving forecasts of events beyond our control, while the prediction of events somewhat within our control can be improved by realising the economic predicament of the forecasting entity. This realisation can be of importance not only for refining predictive accuracy but also for contributing to the existence of a successful exploration industry.
LEGAL CONSIDERATIONS AND NEGOTIATION OF JOINT EXPLORATION AGREEMENTS
Authors: Lacher S. R.
Published: August 2017

In order to understand the basic elements of a joint exploration agreement, comparisons must be drawn with existing types of legal relationships. A joint exploration agreement, whether formed de novo or created by farming-out, is analogous to a partnership. The analogy to a partnership therefore, explains a number of standard provisions in a joint exploration agreement or farm-out, which though standard and familiar, are there for purposes which are not altogether obvious and have greater flexibility in their framing and potential for innovation to fit specific commercial circumstances. This leads to an examination of the wide range of business relationships, which fall under the general description of a farm-out. Specific types of documents are needed to effect the legal relationship of the parties. Specific provisions of farm-out agreements and operating agreements must be examined to highlight areas for particular attention in negotiations.
THE NORTH PAARATTE GAS DISCOVERY
Authors: McPhee I. , McNicol M. D. , Harrison D. M.
Published: August 2017

The North Paaratte 1 gas discovery well was drilled, in November 1979, on the Port Campbell High in the Otway Basin to test a discrete structural closure 3.5 km from the Frome-Broken Hill Port Campbell 1 well, which discovered gas in non-commercial quantities in 1959. A number of other minor gas flows have been encountered in wells drilled since 1959 in the vicinity, but none have beeen commercial.A rate of flow of 9.6 MMcf/D was substained on production testing of the North Paaratte discovery well. This is the first discovery to have possible commercial significance in the Otway Basin, which has attracted a moderate level of exploration effort for the past 25 years.The gas at North Paaratte is reservoired in the Waarre Sandstone of earliest Late Cretaceous age; the probable source of the gas being the underlying Early Cretaceous Otway Group. The structure relies on faulting for closure and is sealed by the Belfast Mudstone, which drapes over the fault block.Post-drill seismic surveys were carried out to map the area of closure and a step-out well to determine the extent of the gas reserve is programmed for early 1981.
COAL SEAM DEGASIFICATION IN QUEENSLAND UTILISING HYDRAULIC FRACTURING WITH FOAM—A CASE HISTORY
Authors: Wilkinson B. , Barro L.
Published: August 2017

Vast reserves of gas-bearing coal deposits are located in Queensland. Owing to the extremely low permeability and porosity of the coal, very low gas flow rates are normally encountered. In an effort to enhance the gas production to economic quantities and to degasify the coal to provide a safer mining environment, four experimental wells were drilled into coal seams near Blackwater, Queensland.Based on extensive laboratory testing of coal samples, computerised fracture design calculations were performed to determine a suitable stimulation programme. The wells were hydraulically fractured with up to 15 000 US gal of foamed stimulation fluid containing 75 per cent nitrogen. To prop open the induced fracture system, 15 000 lb of sand was pumped with the foam. The maximum concentration was eight pounds of 20-40 mesh sand per gallon of fluid. Gas production from the unstimulated wells was too low to measure. Early production data soon after the fracturing suggested a gas flow rate of approximately 50 Mcf/D.
AN ELECTROMAGNETIC METHOD FOR RAPID BASIN EVALUATION AND SOME SPECIAL PROBLEMS
Authors: Vozoff K. , Cull J. P.
Published: August 2017

The magneto-telluric method uses natural electro-magnetic fields to show the resistivity structure of the earth. Resistivity is then related to porosity as in well-log interpretation. The magneto-telluric (MT) method is widely used for rapid basin evaluation and for a range of special problems.Two of these applications are illustrated by Australian examples. One is rapid inexpensive reconnaissance of a porous section overlying basement. The other is penetrating overthurst material and other situations that give rise to surface problems in reflection seismic surveys.In an example from the Murray Basin, a –40 mgal gravity anomaly was easily shown to involve no more than 200-300 m of porous section over resistive basement.A Cooper Basin example is cited to emphasise the flexibility of the method. Good data were obtained at a time of widespread flooding, when readings could only be done on high ground. It was neither possible nor necessary to have sites on continuous traverse lines.Recent reflection work on the northern margin of the eastern Officer Basin has been able to resolve very little detail beneath the Musgrave Block overthrust. MT work disclosed the thin-skinned nature and a number of other structural features of this thrust, improving on an earlier gravity picture. However, south of the thrust the seismic section had much higher resolution. The combination appears to show a thick evaporite-carbonate zone.MT research is continuing, with a survey in the Eromanga Basin late in 1980. However, for the technique to contribute to Australian exploration it will be necessary for commercial crews to begin work. Contract crews typically consist of five or six men with two or three vehicles. Overall monthly cost of such surveys is $10 000-$50 000, or roughly 10 per cent that of reflection survey and processing.
AN ISOTOPIC STUDY OF GASES AND HYDROCARBONS IN THE COOPER BASIN
Authors: Rigby D. , Smith J. W.
Published: August 2017

Gases and/or liquid hydrocarbons from a total of some 70 locations and stratigraphic levels in the Cooper Basin have been isotopically analysed for D and 13C. Measurements on liquid hydrocarbons show significant variation in 13C contents in accord with the view that the Tirrawarra Formation is the most oil-prone sequence. The constancy in 5D values is interpreted as confirming a similar freshwater environment of maturation for all the condensates and oils examined.Isotopic and compositional differences between natural gases from humic sources and coal seam gases suggest that dispersed organic matter (DOM) rather than seam coal is the main source of gaseous and liquid hydrocarbons in the Copper Basin.Carbon dioxide, which occurs in gases in concentrations varying from 50 per cent, proves to be of considerable interest. Although current views appear to favour the thermal decomposition of humic (coaly) material as the major source of this gas, the isotopic data suggest such an origin to be unlikely. On the present evidence a source associated with the underlying granite is preferred.
THE PETROLEUM POTENTIAL OF THE EASTERN ARROWIE BASIN AND FROME EMBAYMENT
Authors: Youngs Bridget C. , Moorcroft E.
Published: August 2017

The eastern Arrowie Basin is a descriptive term for the present-day structurally defined Cambro- Ordovician basin approximately coinciding with the Curnamona Shelf depositional feature which formed on the eastern stable flank of the Adelaide Trough. Remnants of the Arrowie depositional basin are preserved in outcrops of the Flinders Ranges and in the subsurface to the east and west of the ranges. The eastern subsurface sub-basin occupies the area around Lake Frome in South Australia and across the border in New South Wales. Much of the eastern sub-basin is overlain by the Jurassic and Cretaceous rocks of the Frome Embayment of the Eromanga Basin.The area has been explored sporadically over at least the past 20 years but no deep wells have been drilled to test exploration targets. This assessment of the prospectivity of the basin is assisted by shallow stratigraphic and mineral drilling, by extrapolation from outcrop, and by regional geophysics.In the deepest part of the eastern sub-basin the total thickness of the Cambro-Ordovician sediments is expected to exceed 2500 m. Potential reservoirs can be expected within both carbonate and sandstone rocks. Good secondary porosity exists in sandstones of the Middle to Late Cambrian Lake Frome Group and good porosity development is predicted within possible ooid shoal deposits.Source material has been demonstrated in outcrop samples with Total Organic Carbon measured at up to 0.35 per cent. It is suggested that petroleum generation probably occurred in Cambrian sediments in the Adelaide Trough (now the area of the Flinders Ranges) and the petroleum migrated east and west to the stable shelf areas. Sufficient depth of burial may also have been attained on the Curnamona Shelf to allow local generation.In the past, the very poor quality of available seismic data has frustrated the mapping of the subsurface in sufficient detail to justify exploration drilling. Recent experimental seismic surveys, however, have produced data of a much better quality. Potential exists for anticlinal, fault and unconformity traps. There is also some potential for stratigraphic traps such as ooid shoal deposits. At this stage an exploration programme to evaluate the potential of this area is being carried out by the licence holders.
LAND-PLANT SOURCE ROCKS FOR OIL AND THEIR SIGNIFICANCE IN AUSTRALIAN BASINS
Authors: Thomas B. M.
Published: August 2017

Many Australian oils are rich in paraffin waxes which are derived from the remains of terrestrial plants. Although the land-plant contribution to oils, particularly those found in a paralic or deltaic environment, is well established, opinion is divided on the ability of non-marine coaly sediments to generate and expel commercial quantities of oil. It appears that some coal measure sequences have generated mainly gas whilst others are the source of large oil accumulations. The composition of coals deposited in Australia has varied through geological time as a result of differences in climate, geological setting, depositional environment and stage of floral evolution. Consequently, most Australian pre-Jurassic coal measure sequences are deficient in exinite macerals and are therefore mainly gas-prone. In contrast, Jurassic to Tertiary coal-rich sequences often contain abundant exinite and may have substantial potential to generate oil in commercial quantities, as demonstrated by the well-known Gippsland Basin (Bass Strait) oilfields.A similar trend is observed worldwide, where, despite the extraordinary global abundance of Late Palaeozoic coals, only minor amounts of crude oil of land-plant origin are known to be associated with them. However, there appears to be a close relationship between the occurrence of waxy, land-plant-derived crudes and coaly sediments of Cretaceous and Tertiary age. This is thought to be a result of the dominance of conifers in swamp floras of these periods, together with the evolution of the angiosperms (flowering plants) in the Late Cretaceous.
HYDRODYNAMICS AND HYDROCARBON MIGRATION — A MODEL FOR THE EROMANGA BASIN
Authors: Bowering O. J. W.
Published: August 2017

Recent oil discoveries in the Eromanga Basin in sediments ranging in age from Early Jurassic to Early Cretaceous provide strong evidence for an oil source within the basin.A recent study of the thermal history of Eromanga Basin sediments within the licence areas of Delhi Petroleum Pty Ltd and Santos Limited indicates that generation and primary migration of oil within the basin occurred within a period ranging approximately from late Cretaceous to Early Tertiary and that these events pre-dated the artesian system, which developed in Plio-Pleistocene times. Generation is believed to have occurred within deeper basin depocentres; migration toward the shallower marginal areas followed.The present artesian system is unlikely to have flushed oil out of existing traps. However, there is evidence that the artesian flow was stronger previously, and may have influenced secondary migration of oil. A mound spring has furnished evidence of possible migration to the western margin of the basin.
A REVIEW OF THE HYDROCARBON HABITAT OF THE EASTERN AND CENTRAL BARROW — DAMPIER SUB-BASIN, WESTERN AUSTRALIA
Authors: Kopsen E. , McGann G.
Published: August 2017

The most completely known section of the Barrow- Dampier Sub-basin in the northern Carnarvon Basin of the Northwest Shelf comprises three depositional super- cycles spanning the Triassic to the Tertiary. Each cycle is made up of an initial transgressive section of mainly fine-grained clastics overlain by a thick, extensive, off- lapping sequence of coarse-grained deposits. The transgressive sedimentary package typically contains a coarse basal unit overlain by a thick, argillaceous unit, whereas the progradational package changes character in each cycle, representing increasingly open marine conditions as the depocentre and its palaeogeography evolved. Continental siliciciastics at the end of the Triassic Supercycle contrast with the marine-marginal marine siliciciastics at the end of the Jurassic-Neocomian Supercycle and the prograding Tertiary carbonate wedge of the youngest cycle. Each of these gross sequences has a distinctive seismic signature upon which are superimposed stratigraphic features reflecting basin evolution from a broad intra-continental depocentre to a mature, passive continental margin basin.In the area east of Barrow Island, potential hydrocarbon source rock quality and richness varies between each cycle but potential source beds frequently occur at similar levels within each supercycle. The Dingo Claystone within the Jurassic-Neocomian depositional package contains by far the thickest and most extensive potential sources in the area and is likely to be the source for most of the hydrocarbon liquids discovered to date in the northern Carnarvon Basin (with the probable exclusion of the majority of the Rankin Platform condensates).The occurrence of oils of mixed composition and considerable variability beneath the Muderong Shale regional seal in areas of low thermal maturity suggests that many of the hydrocarbon liquids have undergone considerable vertical migration and have also a complex genesis. Furthermore, saturate-rich liquid hydrocarbons overprinting an older biodegraded oil are recognised in a number of wells along the basin margin hingeline. The likely migration and entrapment model for the majority of hydrocarbons discovered to date in the area under review involves dynamic charging of reservoirs, mainly during the Tertiary. Two main pulses of generation and migration are recognised in the eastern portion of the sub -basin, and a third phase is probably occuring at present-day, west of Barrow Island.
VSP CASE HISTORY, KANPA 1A, THE WESTERN OFFICER BASIN
Authors: Prudence T.J.C. , Flentri J.
Published: August 2017

The Kanpa 1A Vertical Seismic Profile (VSP) was conducted for Shell by Schlumberger and incorporated variable time and depth sampling, different source offsets and recording in cased and uncased hole. Processing was performed using Shell proprietary programs, with particular attention to:Editing and resampling of the data setSeparation of upgoing and downgoing waves using FK and median filtersComparison of gain recovery based on modelling the amplitude decay of direct arrivals with an averaging process (AGC)Sensitivity of the final VSP stack to blanking of residual tube wave noiseZero-phase whitening of the VSP traceStacked VSP traces for Kanpa 1A were compared with a zero-phase seismic section and synthetic seismogram at the well. The VSP/seismic match is good and, due to poor synthetic/seismic correlation, was the basis for the final seismic/well tie. Interpretation of deep VSP data enabled the estimation of formation boundaries below the total depth of the well.It is concluded that VSPs can be invaluable in establishing well ties where seismic is poor or when detailed correlation is required (e.g. stratigraphic traps). Reflectors "ahead of the bit" can be interpreted from VSPs based on assumed velocities and VSP/seismic tie, and the predicted thickness and seismic character of the target interval. A consistent field configuration is recommended for acquisition with attention to tube wave suppression and adequate spatial and temporal sampling. Previous processing experience is advantageous if quick and reliable VSP results are required for decisions while drilling.
APPLICATIONS OF THERMAL MULTIGATE DECAY PULSED NEUTRON LOGS IN UNUSUAL DOWNHOLE LOGGING ENVIRONMENTS
Authors: Ajam Sami O. , Rahal V.E.
Published: August 2017

The Thermal Multigate Decay (TMD) logging system utilizes a pulsed 14 Mev generator and two gamma ray detectors to obtain measurements of the capture cross sections of downhole formations. The composite decay curve from both formation and borehole capture gamma rays is detected, and is separated into the two individual components : sigma formation and sigma borehole. The resulting sigma formation measurement is only minimally affected by borehole conditions, especially in cased wells.In addition to sigma formation and sigma borehole, the TMD system generates a dual-spaced porosity ratio and several other parameters which provide information on log quality, borehole parameters, and tool stability. These features can be used to assist the log analyst in understanding the down- hole borehole environment as well as formation characteristics. Under appropriate conditions, the TMD log can also provide production logging information relating to fluid movement in or near the wellbore.The paper briefly reviews the TMD logging system, after which it concentrates on log examples in unusual borehole conditions : logs run across intervals where borehole conditions change; logs run in air filled boreholes; logs run in badly washed out boreholes; logs run through stuck drill pipe/ collars; logs run in flowing wells. The supplemental TMD curves in these situations identify the presence of gravel packs and packers, changes in borehole fluid salinity, possible communication between zones, and water and oil producing perforations. Gas in the borehole can also be clearly differentiated from gas in the formation.
ALIENATION OF LAND FROM EXPLORATION—A SOUTH AUSTRALIAN EXAMPLE
Authors: Laws R.A.
Published: August 2017

The mineral and petroleum industry has played a vital role in the development of South Australia, historically, culturally, and economically. In 1985 more than $1 billion worth of production contributed over $50 million in royalties to the state's revenues plus a range of taxes to the Commonwealth. Other benefits included infrastructure establishment, employment, and the training and development of expertise in the workforce.Access to the land surface for exploration is vital if the state's subsurface resources are to be discovered and developed. Over the past ten years, however, there has been a major increase in limitations on access to land for exploration in South Australia. Currently, access to 29 per cent of the state is restricted to some extent, mostly due to National Parks, Aboriginal land, and both Commonwealth and State heritage legislation. Proposals are in hand which could result in the restricted area increasing to over 40 per cent.Less than 0.1 per cent of the area of the state has been directly involved in resource exploration and development. Despite this, and despite successful introduction of codes of practice to limit the effect of exploration activities and to speed rehabilitation of access tracks and drillsites, the industry is generally and erroneously perceived to be a major land user. This is evidenced in community attitudes and reflected in recent legislation. A greater effort is required to ensure that exploration is not stifled by excessive limitations on the right of access to land.
HARRIET — ONE YEAR FROM APPROVAL TO PRODUCTION
Authors: Self R.H. , Macey D.
Published: August 2017

The Harriet oilfield is located offshore Western Australia, north of Onslow and west of Dampier, close to the Lowendal islands. The original estimate of oil in place is approximately 60 million barrels and constitutes a truly marginal field development.A feasibility study comparing various options for production facilities was prepared initially. A conventional eight-legged jacket with well template and two production decks was selected as cost effective with relative ease of design in meeting the environmental criteria. Nearby Varanus Island was chosen as the operations base and storage terminal, with an eight-point conventional spread mooring for the tanker loading export facility.Environmental Protection Agency and Mines Department approvals were received in May 1985. The state of planning, engineering and pre-ordering was such that the 'A' platform was installed by the end of November some six months after approval; the island storage was ready to accept production by mid-January when the wells were tied in. Production commenced on 18 January 1986, one year and 11 days from participant budget approval, and seven and one-half months after government approvals.Simultaneously with construction, field extension to the north was proven in August, and approved for development in September. The necessary pipelines to the two satellites 'B' and 'C' were prepared on the island and installed in January 1986. The satellite platform schedule was delayed by industrial action but installation was completed in July and production from the field extension commenced in early September.Local materials, equipment and contractors were used to the greatest extent possible. A measure of this is that the equivalent of 14 per cent was spent overseas out of a development total of over $150 000 000.
THE GEOLOGY OF THE MOUNT HORNER OILFIELD, PERTH BASIN, WESTERN AUSTRALIA
Authors: Warris B.J.
Published: August 2017

The Mount Horner oilfield is located 30 km east of the town of Dongara, some 360 km north of Perth, Western Australia. It was discovered by WAPET in 1965 but it was not until 1980-81 that a further four appraisal wells were drilled on the field. One additional appraisal well was drilled in 1987.The structure consists of a tilted fault block downthrown to the east with a roll-over anticline on the downthrown side of the fault. Sandstones within the Lower Triassic Kockatea Shale produced oil in 1965 from Mount Horner No. 1 on the upthrown tilted fault block. This well was eventually plugged and abandoned due to the low productivity of the reservoirs and the then prevailing low oil price. Production also occurred in the Basal Triassic Sandstone on the downthrown side of the fault. Mount Horner Nos 4 and 5 produced from this horizon from 1984 to 1986, when they were shut in due to increasing water cut.At the top of the Lower to Middle Jurassic Cockleshell Gully Formation, a complex transition zone exists between the fluvial sandstones of the Cattamarra Coal Measures Member and the marine sediments of the Champion Bay Group. Sandstones in this transition zone produce oil from Mount Horner No. 5 which was re-completed in 1986 and from No. 7 which was drilled in 1987.There are four distinct oil pools on the Mount Horner structure. Geochemical and maturation studies have shown that the bulk of the reserves was generated from the basal part of the Kockatea Shale and has migrated up the main fault and into the Jurassic reservoirs.Recent workover and appraisal drilling programs on the field have established the first commercial oil production from Jurassic sediments in the Perth Basin. This opens up an exciting new exploration play in the northern Perth Basin.
CAPITAL GAINS TAX — ASPECTS OF CERTAIN FINANCING TRANSACTIONS
Authors: Wilson Peter A.
Published: August 2017

The Australian Income Tax Assessment Act, 1936 (the Act) has recently been amended by the inclusion of a full capital gains tax system.This system is particularly applicable to various aspects of financing transactions into which petroleum exploration and development companies may enter.In the light of recent changes to the means by which petroleum companies can access the capital markets, it becomes necessary to consider these issues. This paper is designed to provide petroleum company executives with additional information on the capital gains tax aspects of:creating royalty, net profit interests and production payments;conventional security management matters;bankruptcy/liquidation matters;allotment of ordinary and preference share issues;allotment of convertible notes;drawing down of conventional loans; andgroup reorganisations.The paper also sets out some recommendations for amendments to the Act designed to correct capital gains driven financing problems.These aspects and 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 problems are to be firstly, recognised and secondly, to the extent possible, overcome.
1989 – COMMERCIAL DEVELOPMENTS
Authors: Stock A.M.
Published: August 2017

The year 1989 provided the oil industry with some respite from the depressed prices of recent years. Burgeoning Asia-Pacific rim demand took OPEC output to levels not seen since the late 1970s. The price outlook is now brighter than it has been for several years.Equity markets offered less comfort. Oil and Gas Index turnover was up marginally on year earlier levels. The market's disenchantment with the industry was not totally undeserved. High interest rates and low prices, coupled in some instances with questionable management practices, saw the demise of several small explorer'producers during the year.Two major international developments occurred in 1989 which will impact on the commercial direction of the industry for the next decade, each summarised in a word:GreehouseValdez.Governments worldwide now seriously contemplate major new taxes on hydrocarbons to reduce world carbon dioxide emissions. Exxon spend US$2 billion cleaning up Alaska in a public relations disaster for it and the industry. Both will have commercial repercussions for years to come, but both will combine to strengthen the role of gas in domestic and international energy markets. Gas built domestic market shared in 1989 and the year heralded Australia's entry into the world LNG trade.In Papua New Guinea, industry learned the meaning of political risk with disturbances bringing mine closures on Bougainville. Reflecting the optimism which is an essential ingredient of the industry, announcement of a go-ahead on the Kutubu oil project in PNH is imminent.
THE DISCOVERY AND DEVELOPMENT OF MOONIE — AUSTRALIA'S FIRST COMMERCIAL OILFIELD
Authors: O'Sullivan T. , A.M. D.J. McGarry , Kamenar A. , Brown R.S.
Published: August 2017

The Moonie Field, located in the eastern portion of the Surat Basin and 300 km west of Brisbane, was discovered in December 1961 by Union Oil, operator of the 'UKA' joint venture consisting of Union Oil, Kern and AOG. Successful appraisal and development drilling led to the construction of the Moonie to Brisbane pipeline in 1963-64. Oil production commenced in 1964 and peaked in 1966 at a rate of 9000 BPD (1.4 ML/d). The oil is reservoired in the Precipice Sandstone and is trapped within the closure of the Moonie Anticline, located on the eastern and upthrown side of the Moonie-Goondiwindi Fault. Of the 38 wells drilled in the field to date, 32 have produced oil at economic rates. By August 1990, 22.23 MMBBL (3.5 GL) of oil had been produced from an estimated 59.1 MMBBL (9.3 GL) in place. Remaining recoverable reserves, with primary recovery, are estimated to be more than 1.5 MMBBL (0.2 GL). Enhanced oil recovery using both carbon dioxide and microbial techniques is currently being investigated by AGL Petroleum.The discovery of oil at Moonie represented the start of the commercial oil era in Australia. It provided encouragement for the petroleum exploration industry to expand the search and demonstrated that there were profits to be made from Australia's sedimentary basins. Moonie spawned a generation of petroleum exploration and production people who contributed to discoveries and developments elsewhere in Australia.