bluuebunny/crossref_metadata_2025 huggingface dataset:
THE KINGFISH FIELD—OFFSHORE GIPPSLAND BASIN
Authors: Bein Jorg , Griffith Brian R. , Svalbe Andrew K.
Published: August 2017

The Kingfish field, currently Australia's largest producing oil field, lies 48 miles offshore southeastern Victoria in 250 ft of water. The field occurs within a large, essentially, east-west trending topographic high on the Latrobe unconformity surface sealed by fine grained clastics of the Upper Eocene Gurnard and Oligocene Lakes Entrance Formations. The reservoir itself is formed by Lower Eocene sediments of interdeltaic origin.The discovery well, Kingfish 1, was spudded on 6 April 1967. This well indicated the severity of a suspected seismic velocity gradient, a function of high velocity channel deposits in Miocene sediments overlying the crest of the Latrobe unconformity surface. Additional seismic coverage and two outpost wells provided sufficient structural and stratigraphic control to define a commercial oil field having a maximum of 270 ft of vertical relief over an area of some 28 sq mi at the oil-water contact of 7,566 ft subsea.Following completion of the 42 well development drilling program for the A and B platforms the Kingfish oil field was put on stream on 21 April 1971. Proved and probable reserves have been initially estimated at 1,060 MM STB. The field has flowed oil at rates in excess of 180,000 STB/D for a cumulative production to the end of 1972 of 83 MM STB.
DIAGENESIS OF ORGANIC MATTER AND OCCURRENCE OF HYDROCARBONS IN SOME AUSTRALIAN SEDIMENTARY BASINS
Authors: Shibaoka M. , Bennett A. J. R. , Gould K. W.
Published: August 2017

It is important that petroleum exploration geologists know the critical depth limits where oil is generated from original organic matter in sediments and where the oil changes to natural gas. Organic matter is very sensitive to temperature. The maximum temperature experienced is related to its depth of burial.CSIRO has used the composition and physical properties of various types of organic matter in shaly rocks as indicators for the degree of diagenesis caused by this heat alteration. The reflectance of vitrinite in associated coals is used as the primary standard, and carbon content of such coals as the secondary parameter to distinguish various stages of oil and gas generation. Depth-reflectance curves are useful 1., for estimating palaeogeothermal gradients, 2., for determining the degree of diagenesis at a particular depth and also 3., for estimating the approximate thickness of sediments subsequently lost after deposition.The petroleum potential of some Australian sedimentary basins is reviewed in the light of this knowledge. In the Northwest Shelf area and in the Capricorn and Otway Basins, the oil generation zone is deeper than in the Cooper, Galilee and Surat Basins. In the Bowen and Sydney Basins and several other small basins along the eastern coast of Australia, this zone is very shallow, and in some areas the oil generation zone has been completely lost by erosion. The areas most promising for oil fields are those where little erosion of sediments has taken place subsequent to deposition and diagenesis, provided that all other geologic factors for hydrocarbon accumulation are present.
PETROLEUM EXPLORATION ACTIVITY IN AUSTRALIA AND PAPUA NEW GUINEA 1972-1973
Authors: Smith E. R.
Published: August 2017

A highlight of 1972 has been the continued success on the Northwest Shelf where it has become apparent that the reserves of natural gas are very large. There have also been two promising oil discoveries in this area.Significant new gas fields were discovered in the Cooper Basin, which have finally assured sufficient reserves for the Sydney market. However the development of the Tirrawarra oil field has been disappointing.Petroleum exploration activity in Australia and Papua New Guinea improved slightly during 1972, mainly because of increased activity in offshore areas. It is likely that this trend will continue through 1973.
EXPLORATION AND GEOLOGY OF THE WEST SULU BASIN, PHILIPPINES
Authors: Bell R. M. , Jessop R. G. C.
Published: August 2017

The West Sulu Basin lies in the western portion of the Sulu Sea. Republic of the Philippines. It occupies an area in excess of 26,000 square miles (67,000 km2) and is bounded to the west and south by the cordilleran arc extending from the island of Palawan through Sabah and along the Sulu Archipelago to the island of Mindanao. To the north-east, the basin probably extends beyond the edge of the continental shelf in Philippine territorial waters.The basin may be broadly divided into a western platform and an eastern deep: the latter is subdivided by northeast-trending basement ridges into three sub-basins. Sediments deposited in these sub-basins are of Tertiary to Recent age and have been affected by several orogenies and by contemporaneous movements of fault-controlled blocks. This has resulted in truncation and the development of marked erosion surfaces and onlap within the Upper Tertiary section. Many anticlinal features mapped within the basin have resulted from drape over basement highs or from penecontemporaneous growth of these highs.Major unconformities associated with Upper Tertiary tectonic events have been recognized onshore. Extrapolation to offshore areas where these events can be seismically mapped has enabled an interpretative geologic model to be built up. Provisional identification of stratigraphic units and their nature have been made using this model.The Upper Tertiary section within the eastern deep is expected to consist of deltaic and paralic reservoir sands interbedded with, grading into and transgressed by deeper water shale and mudstone with good hydrocarbon source potential. Some limestone lenses may be present.The presence of Lower to Middle Miocene diapiric shale and Plio-Pleistocene intrusives coupled with data of variable quality makes seismic interpretation difficult in some areas. However, several large anticlinal features and a number of stratigraphic and combination traps have been located.A non-commercial discovery of oil and gas has been made in the basin.
THE GEOLOGICAL EVOLUTION OF THE SOUTHERN TAROOM TROUGH AND THE OVERLYING SURAT BASIN
Authors: Exon N. F.
Published: August 2017

Isopach, structure contour, and palaeo-geological maps illustrate the geological development of the southern Taroom Trough and the lower part of the Surat Basin sequence.The meridional southern Taroom Trough, 50,000 km2 in area, is a southerly subsurface extension of the outcropping Bowen Basin. It is fault-bounded to the east and plunges northward. The maximum thickness of sedimentary fill increases northward from less than 400 m to 10,000 m, and consists of Lower Permian marine sediments, Upper Permian coal measures, Lower Triassic redbeds, and Middle Triassic stream sediments. The trough's present western margin is depositional, but the faulted eastern margin started to form in the Late Permian in the south and in the Early Triassic in the north; movement ceased in the Early Triassic in the south and in the Late Triassic in the north. Tectonic movements did not recur until Late Jurassic time.Late Triassic erosion preceded deposition of Surat Basin sediments. These sediments extended over ever wider areas, even the basal sands spreading far beyond the Taroom Trough. The fully-developed Surat Basin is 300,000 km2 in area, and contains up to 2500 m of dominantly continental Jurassic sediments and dominantly marine Lower Cretaceous sediments. Lower Jurassic stream sediments (the main petroleum producers of the basin) are thickest and coarsest above the Taroom Trough, suggesting steady subsidence and compaction of the trough sediments.By the Late Jurassic this compaction had virtually ceased, and epeirogenic uplift had given the basin its present shape, with the Mimosa Syncline (above the Taroom Trough) and the south-westerly-trending Dirranbandi Syncline (above a basement depression) being major structural features.Petroleum, which is probably derived from both Permian and Jurassic sources, is most abundant in the Lower Jurassic sandstone on either side of the Mimosa Syncline. Some aspects of the migration and trapping of Permian petroleum are discussed, and it is suggested that the Lower Jurassic Hutton Sandstone in the virtually unexplored Bollon area could be prospective.
IMPROVED MULTIPLE ATTENUATION IN COMMON DEPTH POINT STACKING
Authors: Wardell John
Published: August 2017

Since the introduction of the common depth point method of seismic reflection shooting, we have seen a continued increase in the multiplicity of subsurface coverage, to the point where nowadays a large proportion of offshore shooting uses a 48 fold 48 trace configuration. Of the many benefits obtained from this multiplicity of coverage, the attenuation of multiple reflections during the common depth point stacking process is one of the most important.Examinations of theoretical response curves for multiple attenuation in common depth point stacking shows that although increased multiplicity does give improved multiple attenuation, this improvement occurs at higher and higher frequencies and residual moveouts (of the multiples) as the multiplicity continues to increase. For multiplicities greater than 12, the improvement is at relatively high frequencies and residual moveouts, while there is no significant improvement for the lower frequencies of multiples with smaller residual moveouts, which unfortunately are those most likely to remain visible after the stacking process.The simple process of zeroing, or muting, certain selected traces (mostly the shorter offset traces) before stacking can give an average 6 to 9 decibels improvement over a wide range of the low frequency and residual moveout part of the stack response, with 9-15 decibels improvement over parts of this range. The cost of this improvement is an increase in random noise level of 1-2 decibels. With digital processing methods, it is easy to zero the necessary traces over selected portions of the seismic section if so desired.The process does not require a detailed knowledge of the multiple residual moveouts, but can be used on a routine basis in areas where strong multiples are a problem, and a high stacking multiplicity is being used.
ANALYSING THE PRESENT TO PREDICT THE FUTURE
Authors: Lane P. B.
Published: August 2017

It is widely believed that the demand for natural resources will grow exponentially and many authors, despite their scientific background use this assumption as a basis for predicting future growth patterns. Examination of the forces which control demand lead us to conclude that the rate of its increase in advanced countries will soon begin to decline. These forces- population, affluence of the population and technical advancement-are beginning to move in a direction so as to limit growth. In what can be assumed to be the most advanced nation, America, population growth is declining, the consumer is becoming saturated with goods so that growth in consumption per head of population is slowing, and technical advancement is leading to far more economic use of natural resources.On the other side of the coin many available resource reserves are growing. Although the concept of finite resources cannot be argued, its application to the present situation in Australia is not valid. Experience has shown that the supply, i.e. reserves of natural resources is greatly increased by their exploitation. Even though total reserves remain the same, discovered reserves, i.e. usable reserves continually grow. Over the past 15 years export of all of Australia's major mineral resources has been allowed and yet despite this the life expectancy of each of these resources has increased dramatically. Also, exploitation of natural resources leads to more efficient methods of extraction, thus allowing massive amounts of low grade reserves to be classified as economic. Investigation of these phenomena indicates that it is an overly simplistic approach to plan for the conservation of resources based on proven reserves only, for often the potential of an area far exceeds those reserves that have already been discovered and this potential can only be realised if an incentive is provided for the explorer.The energy crisis. Shortages of fuel. The Club of Rome. Exhaustion of resources. Population explosion. Shortages. Exponential growth. Doomsday.
THE ECONOMICS AND STRATEGY OF LNG
Authors: Linnett D. T.
Published: August 2017

The natural gas industry in Australia is growing rapidly and this is an opportune time to look at the possible place for Liquid Natural Gas (LNG) in this expanding field.In general, as the demand for natural gas increases, and its distribution becomes more widespread, so the economics become more favourable for using LNG for peak shaving, standby purposes, or trucking to satellite vaporising stations. Apart from demand, however, a large number of other factors affect both the decision as to what type, if any, of LNG facility is warranted, and the selection of types and sizes of equipment for that facility. These factors include environmental considerations, calorific value (CV) and Wobbe Index limitations, purification problems, transport facilities, pipeline capacity limitations, climate, etc.In the United Kingdom, the use of LNG is now well established in a number of different roles, and much experience has been obtained in the planning, design, construction and operation of LNG installations. Whilst the growth patterns in Australia and the UK are similar, however, the requirements for storage are substantially different.It is concluded that, as the gas demand in Australia increases, and the distribution network becomes more widespread, LNG facilities may well become economic propositions to fulfil a number of combined roles.
DETERMINATION OF EXTREME VALUES OF WAVES, WINDS CURRENTS, AND TIDES FOR THE DESIGN OF OFFSHORE INSTALLATIONS
Authors: Aagaard P. M.
Published: August 2017

Frequently the only relevant information available to a designer about a propective offshore platform site is its location, the water depth, and whatever can be gleaned from oceanographic atlases. In spite of this lack of data the platform designer is faced with the problem of selecting design parameters such that the proposed platform will not fail during its exposed life. He therefore needs to know what are the greatest wave height, current speed, etc., the platform will experience, and must specify studies that can provide the needed information on extreme values. This paper discusses methods used in such studies and their associated uncertainties.The method for acquiring extreme value data should be chosen on the basis of available oceanographic and meteorological data for the site, reliability requirements, time available before final design, and cost. Wave height is usually the most critical design parameter. Data over a long time span (e.g. greater than ten years) are needed to achieve reliable extreme values. Measured wave data covering such time spans are almost never available for a site of interest, and schedules seldom permit lengthy data-collection periods. Frequently the most reliable extreme wave heights can be obtained by calculating wave heights (i.e. hindcasting) from windfields derived from historical weather charts and fitting certain extreme-value distribution functions to the hindcast results. This preferred approach should include calibration of the wave height calculation method with local measured data. Alternative approaches, usually involving greater uncertainties in predicted extremes, are also appropriate for particular cases. Methods for determining extreme winds, currents, and tides are similar to those used for extreme waves, but some differences result from the nature of the phenomena and the type of data typically available.
PRELIMINARY CONCLUSIONS FROM PRESSURE TRANSIENT TESTING AT PALM VALLEY.
Authors: Gruy H. J. , Sharp John S. , Garb Forrest A.
Published: August 2017

THE PALM VALLEY structure is located about 75 miles southwest of Alice Springs, Northern Territory, and is a large gentle structure located in the north central part of the Amadeus Basin. It was discovered gas productive by the drilling of the Palm Valley No. 1 well completed May 20, 1965. The No. 1 well was drilled to a total depth of 6,658 feet and produced gas from the lower Stairway, Horn Valley and upper Pacoota formations of Ordovician Age.Since completion of the No. 1 well, two additional wells have penetrated the Palm Valley structure. Because the producing characteristics of the three wells vary considerably, an extensive pressure transient testing program has been carried out in order to estimate reservoir characteristics and to estimate the range of the potential reserve for this structure. The transient pressure tests when analyzed by the most modern techniques accepted by industry indicate widely varying storage capabilities and in some instances yield results which are not easily correlated with geological interpretations.The purpose of this paper is to present the theory and the results of the transient tests performed to date and to discuss the possible meaning of the pressure behavior.
STRUCTURE AND DEVELOPMENT OF THE SOUTHERN MARGIN OF AUSTRALIA
Authors: Boeuf M. G. , Doust H.
Published: August 2017

Off the southern coast of Australia, exploration results and deep-water reconnaissance seismic data support the concept of an aseismic Atlantic-type continental margin. Characteristic is a sedimentary wedge which extends from the shelf to the abyssal plains and includes crustal elements of continental and oceanic origin.Oceanward, a continuous level of diffractions ascribed to the top of oceanic crust can be observed on seismic records, steeply dipping beneath the continental rise towards a smooth, flat, often faulted reflector which is correlated with top Precambrian or Palaeozoic continental basement.The sedimentary wedge which overlies the block-faulted and collapsed continental basement is subdivided by unconformities into: (a) a continental Lower Cretaceous unit and a fluviodeltaic unit of Upper Cretaceous-Danian age which are taken to represent rift valley stages of deposition controlled by extensional tectonics and (b) a post-breakup sequence of Tertiary units representing regional collapse and out-building of the shelf. The Upper Cretaceous sequence is missing along much of the continental edge where Tertiary sediments appear to rest directly on the Lower Cretaceous unit.Our interpretation suggests that a prolonged period of uplift took place along the axis of the rift valley prior to continental break-up. On the basis of palaeomagnetic data and biostratigraphic analysis the breakup phase started in the Upper Paleocene.From the continent outward several structural zones can commonly be recognised: (a) a zone of shallow basement with a thin Lower Cretaceous cover normally faulted and overlain by thin gently dipping Tertiary beds, (b) a zone of faulted and landwards tilted basement blocks and Lower Cretaceous sediments overlain (sometimes with clear unconformity) by thick Upper Cretaceous sediments, (c) a zone of thick, moderately deformed Tertiary sediments whose axis of deposition is generally offset to the south of the Upper Cretaceous basinal axis, (d) a zone of rotational faults and associated toe thrusts affecting the Cretaceous sediments and apparently related to the time of margin collapse, (e) an area of little disturbed Cretaceous and Tertiary sediments overlying continental basement. This zone extends into the "magnetic quiet zone" which is therefore believed to be, at least in part, a collapsed portion of the continental margin adjacent to oceanic crust.The interpretation of the geological evolution of the southern Australian margin based on the stratigraphic and structural data presently available can be related to current theoretical models on continental margin development.
DIRECT SEISMIC DETECTION OF HYDROCARBONS
Authors: Pailthorpe W. , Wardell J.
Published: August 2017

During the past two years, much publicity has been given to the direct indication of hydrocarbon accumulations by "Bright Spot" reflections: the very high amplitude reflections from a shale to gas-sand or gas-sand to water-sand interface. It was soon generally realised, however, that this phenomenon was of limited occurrence, being mostly restricted to young, shallow, sand and shale sequences such as the United States Gulf Coast. A more widely detectable indication of hydrocarbons was found to be the reflection from a fluid interface, such as the gas to water interface, within the reservoir. This reflection is characterised by its flatness, being a fluid interface, and is often called the "Flat Spot".Model studies show that the flat spots have a wide range of amplitudes, from very high for shallow gas to water contacts, to very low for deep oil to water contacts. However, many of the weaker flat spots on good recent marine seismic data have an adequate signal to random noise ratio for detection, and the problem is to separate and distinguish them from the other stronger reflections close by. In this respect the unique flatness of the fluid contact reflection can be exploited by dip discriminant processes, such as velocity filtering, to separate it from the generally dipping reflectors at its boundaries. A limiting factor in the detection of the deeper flat spots is the frequency bandwidth of the seismic data. Since the separation between the flat spot reflection and the upper and lower boundary reflections of the reservoir is often small, relatively high frequency data are needed to resolve these separate reflections. Correct display of the seismic data can be critical to flat spot detection, and some degree of vertical exaggeration of the seismic section is often required to increase apparent dips, and thus make the flat spots more noticeable.The flat spot is generally a smaller target than the structural features that conventional seismic surveys are designed to find and map, and so a denser than normal grid of seismic lines is required adequately to map most flat spots.
FIELD INVESTIGATIONS FOR NORTH WEST SHELF DESIGN CRITERIA
Authors: Stroud S. A. , King R. W.
Published: August 2017

Since 1971, when major gas discoveries on the North West Continental Shelf were confirmed, B.O.C. of Australia Limited (BOCAL), as operator for the Northwest Shelf Consortium, has carried out a major programme of environmental data collection. The purpose of the data collection programmes and follow-up studies has been to define engineering design criteria for evaluation of offshore production structures and pipelines.Prior to the commencement of exploration drilling, little was known of the meteorological/oceanographic regimes of this vast offshore area and no published data existed on the sea bed topography or composition. During the past 3½ years a substantial library of environmental information has been assembled using both conventional and the most modern techniques available. Acquisition of field data has been mainly concentrated in the southwestern portion of the Consortium's lease area where the major exploration effort was maintained.During the course of the programme, weather instrumentation on all exploration rigs was upgraded. Wave measurement and current metering programmes were also carried out to ascertain the modes of water movement at various offshore discovery locations. To assess the foundation materials and qualities, test borings were carried out at 6 exploration well sites, including a series of in-situ pile load tests at the North Rankin location. Preliminary surveys over possible offshore pipeline routes were carried out to assess the nature and topography of the sea bed.Information gained from the programme of field-collected data and related environmental studies has enabled BOCAL to proceed confidently with platform design for the production of gas from the North Rankin Field.Work is continuing on the acquisition of further field environmental data in order to improve the understanding of the meteorology and oceanography of the North West Shelf area. This will assist in further evaluation of offshore design criteria for the North West Shelf of Australia.
BARRIER REEF REVISITED: AN APPRAISAL OF THE ROYAL COMMISSION REPORT
Authors: Foster Bob
Published: August 2017

A CONTROVERSY arose in the late 1960s regarding the effect of the crown-of-thorns starfish Acanthaster planci (Lamarck) on the Great Barrier Reef. At that time of public concern, oil exploration was announced in the vicinity of the reef. In response to public outcry, the Federal and Queensland governments created the Great Barrier Reef Petroleum Drilling Royal Commissions.The Commissions acted as one Commission and sat for the first time on 22 May, 1970. Their terms of reference related to risks involved and effects of leaks if drilling for petroleum was allowed in the Barrier Reef province; areas where drilling could be allowed and conditions to be imposed; and probable benefits of drilling. Hearings continued intermittently until 3 July, 1972, and a summary of findings was released on 22 November, 1974.The Commission found a small but real risk of blowouts, but were unable to predict the effect of unweathered oil on corals and associated organisms; they found that drilling could take place within certain areas of the province remote from reefs, with appropriate safety precautions; they were not able to quantify the potential benefits of drilling.
THE GENESIS OF PERMIAN AND LOWER TRIASSIC RESERVOIR SANDSTONES DURING PHASES OF SOUTHERN COOPER BASIN DEVELOPMENT
Authors: Stuart W.J.
Published: August 2017

The genetic differentiation of Permian Lower Triassic quartz sandstones and other rock-types has elucidated more fully our understanding of sedimentary processes during the course of time in the southern Cooper Basin. Core and ditch samples analyses in conjunction with log signatures provide a strong stratigraphic tool for constructing various types of maps which help in the exploration and development of hydrocarbons in this basin. Various percentage maps using gross genetic members have delineated areas of stream sediment transport, deltaic centres and shoreline-offshore sediments. Although channel-lag to point-bar sandstone reservoirs still offer gas and liquid potential, stratigraphic delta front-shoreline sandstones exhibiting excellent reservoir characteristics are also considered to be worthwhile targets in the basin.Various depositional models are usually more widespread than sites of local anticlines which appear to have undergone varying rates of sinking, relative to one another and also to adjacent low areas during intervals of Permian-Lower Triassic sediment accumulation. Although unconformities are probably widespread in marginal areas of the basin, deposition is considered to have been essentially continuous in parts of the Nappamerri 'synclinoria- like' low - the main depositional and structural axis of the basin. Facies analysis tends to support the belief that anticlinal complexes have never shown abrupt relief during the sediment accumulation of the Gidgealpa Group even though in some areas crestal unconformities are common. It is suggested that local 'structural growth' is genetically related to the differential downwarping of the basin. Episodes of greater mobility of the basin rims are indicated by both unconformities and facies relationships. It is apparent, however, that facies patterns indicate only local entry of sediment transport into the basin particularly in its southern portions. During some phases of sediment accumulation climate may have blurred the larger-scale earth movements. It is suggested by this local study that similar genetic models and mapping techniques could be applied to other Permian basins in the region.
RESERVOIR AND SOURCE ROCK POTENTIAL OF THE LARAPINTA GROUP, AMADEUS BASIN, CENTRAL AUSTRALIA
Authors: Kurylowicz L.E. , Ozimic S. , McKirdy D.M. , Kantsler A.J. , Cook A.C.
Published: August 2017

The quality of reservoir and source beds in the Cambro-Ordovician Larapinta Group of the Amadeus Basin ranges from poor to good.A general northerly decrease in porosity from about 12% at the BMR AP3 locality, to 4% in the Palm Valley area about 50 km to the northwest, is evident in the two known reservoir formations (Pacoota Sandstone and Stairway Sandstone). This regional variation in porosity is related to the depth of burial of the reservoir sandstones and their proximity to the thrust zones on the northern margin of the basin in the MacDonnell Ranges. Growth of authigenic silica has reduced primary intergranular porosity. However fracturing - developed locally in response to erosional unloading of the eastern part of the basin during the Rodingan Movement, and subsequently extended and enhanced by the Alice Springs Orogeny provides a secondary fracture porosity. The total storage capacity (average porosity x net porous thickness) of the reservoir sands is greatest in the centre of the basin.The Horn Valley Siltsone averages 1% total organic carbon (TOC) and contains up to 225 milligrams of extractable organic matter (EOM) per gram of TOC, confirming its suspected source potential. The unusual C15+ normal alkane profile of Mereenie oil is found only in the EOM of fossiliferous shales from the Horn Valley Siltstone and the Pacoota Sandstone.A northeasterly increase in the level of organic maturation of Larapinta Group sediments across the central northern sector of the basin accounts for the occurrence of light oil in the Mereenie field, but only gas (with minor condensate) in the Palm Valley field. The reflectivity of coalified graptolite fragments in the Horn Valley Siltstone and Pacoota Sandstone from the Mereenie area indicates a rank equivalent to medium-volatile bituminous coal and places the formation in the 4oil phase-out zone'. At Palm Valley similar particulate organic matter has reached semi-anthracite grade. Accordingly, the proportion of wet gas (C2+) components in reservoir gas (C1 to C4) decreases from 21-38% in the Mereenie field, through 13% at Palm Valley, to 9% in West Waterhouse No. 1.Hence, the most favourable juxtaposition of prospective source and reservoir rocks within the Larapinta Group would appear to exist in the Mereenie-Gardiner Range area.
THE GEOLOGY OF THE WEST TRYAL ROCKS GAS FIELD
Authors: Meath J.R. , Bird K.J.
Published: August 2017

The West Tryal Rocks gas field is located offshore at the western margin of the Barrow Sub- basin, in the Carnarvon Basin of Western Australia. It was discovered by West Australian Petroleum Pty Ltd ( WAPET) in 1973 on a southwesterly extension of the Rankin Platform where, farther north, a number of major gas/condensate discoveries have been made by Burmah Oil Company of Australia Ltd (BOCAL) since 1971.The productive structure at West Tryal Rocks lies at a depth of 3200 m in about 150 m of water. It consists of an elongate north - trending uplifted block of Triassic and possibly Lower Jurassic reservoir rocks called the Mungaroo Beds.The block is unconformably capped by the Lower Cretaceous Muderong Shale which also provides the lateral seal across the bounding faults. The reservoir section dips to the north at a greater rate than does the sealing unconformity so that progressively younger pre-Cretaceous sediments subcrop the unconformity in that direction.Shales of Middle to Late Jurassic age in the Barrow Sub-basin to the east are believed to be the primary source of hydrocarbons, although the overlying Muderong Shale cannot be ruled out.Three main gas-bearing sands have been encountered by the two wells drilled to date. The second well was drilled up-structure from the first and penetrated 144 m of net gas pay of which 133 m is contained in the three sands. The sands are mainly medium to very coarse grained and possess good porosity and permeability.Preliminary reoervvs estimates indicate that the field contains in excess of 28 x 109 m3 (1 x 1012 ft3) of gas (Playford, 1975).The West Tryal Rocks gas field is unique compared to the other Northwest Shelf fields, in that it is slightly overpressured and contains up to 28% of non-combustible gases - predominantly carbon dioxide and nitrogen. Additionally, the field possesses relatively fresh underlying formation waters with high concentrations of bicarbonate ions.
SOME ASPECTS OF THE GEOLOGY OF THE RUNDLE OIL SHALE DEPOSIT, QUEENSLAND
Authors: Lindner A. W. , Dixon D. A.
Published: August 2017

The presence of oil shale near The Narrows between Rundle Range and Curtis Island, Queensland, has been known for many years, although the only previous efforts at evaluation of the deposit were during World War II by the Queensland Mines Department and subsequently by Carpentaria Exploration Company in 1969-70. The price increase of oil from OPEC sources has once again made oil shale a possible alternative energy source.Core drilling over the past two years in a relatively restricted area near The Narrows by Southern Pacific Petroleum NL and Central Pacific Minerals NL (2330 m in 19 holes) suggests the persistence of oil shale beds over a strike distance of 7 km with a width of 1000 to 2500 m and a composite thickness of at least 427 m. What appears initially as a monotonous sequence of shales and mudstones is found to be remarkably constant lithologically across the range of borehole control. Four lithologic units are recognised, three of them with a significant and persistent content of hydrocarbon compounds.Limited chemical and petrographic studies indicate that the sequence mineralogically comprises a mixture of quartz, clay minerals, minor carbonates and varying amounts of kerogen. Ostracods are the most common and persistent fossil form but gastropods and crustacean, fish, reptilian and algal remains occur at intervals. Plant and spore material are present but not common. The age of the sequence is early Tertiary. The faunal assemblage and sedimentary features suggest that the deposit accumulated under quiet, essentially reducing conditions in a fresh water lake. In the region of borehole control, the sequence dips to the southwest and west at from 4° to 10° apparently as a result of minor tectonic adjustments in common with other coastal Queensland Tertiary deposits.Systematic assaying of the oil shale at Rundle suggests that an average grade of 89 I of shale oil per tonne persists at a waste-to-resource ratio of about one-to-one over an area of 1400 hectares. While in-fill drilling is needed to confirm these figures, the dimensions of the resource indicated is at least 1200 million tonnes of oil shale which contains the equivalent of 600 million barrels of oil in this area. Further exploration drilling will probably indicate an extension of the deposit.
SOME GOOD ONSHORE PETROLEUM PROSPECTS IN AUSTRALIA
Authors: Laing A.C.M.
Published: August 2017

On onshore Australia there are only a few areas where he density of drilling has reached even what Dr. Busch las referred to as sparse coverage i.e., wells 10 miles apart. Consequently it is foolish to write off Australian Inshore sedimentary basins.However there is enough information around now to grade areas in the sedimentary basins onshore and the writer has done so.The factors used are:Either shows of oil or gas in potential reservoir beds or favourable source rock shales with interbedded sandstone or carbonate reservoir beds at a low enough degree of metamorphism to prevent the hydrocarbons and the porosity of reservoir beds being destroyed.Favourable early stratigraphic trapping situation, i.e., an onlap or hingeline situation.Area good for structural elucidation either from surface geology plus core drilling or from seismic. Based on these factors there are 2 potential groups of areas.Round known commercial fields onshore. This is obvious and is not considered further here.The following structures or areasEthabuka Structure. Georgina Basin. Queensland.Pincombe Range Structure, and other structures. Bonaparte Gulf. Western Australia.Otway Basin.Gambier Embayment. Western Victoria.The characteristics of these areas are briefly dealt with. They are all areas which are virtually undrilled.
GIPPSLAND'S OLD AND NEW OIL
Authors: Brown B.R.
Published: August 2017

The Gippsland Basin, initiated in the late Cretaceous, accumulated as much as 4,500 m. (15,000 feet) of sediment before the first major structural movement in the early Eocene, when faulted anticlinal structures and pronounced regional westerly dip were developed in the Latrobe Group.Over the next 13 m.y. of the Eocene, sediment supply was reduced and much of it trapped in the western portion of the basin. On the eastern marine edge of the basin the Tuna-Flounder Channel was cut and filled over a period of 4 m.y. Subsequent erosion, sometimes severe, particularly in the Marlin area, created the significant unconformity on top of the Latrobe Group reservoir sediments. Much of that surface was covered with fine-grained marine sediment of early Oligocene age, leaving only a few high-standing areas unsealed for a further period of 25 m.y. until the mid-Miocene.Later structural movements, in the mid-Miocene (10 m.y.B.P.), were largely vertical with some anticlinal warping. New potential traps were created then and some older structures rejuvenated. Following the latter period of anticlinal growth, a major marine channel system was formed by erosion 9 m.y.B.P. and subsequently engulfed by rapid deposition of prograded wedges of sediment on the continental margin.Oil and gas have been formed from land-derived organic matter deposited in the Latrobe Group during late Cretaceous to Eocene times (100.37 m.y.). Subsequently the oil and gas accumulations have developed their distinctive geographical distribution with the major oil fields buried deeper than the major gas fields. It appears that oil has migrated and been trapped at intervals over the last 60 m.y. under varying overburdens from about 100 m. to about 2,000 m. as indicated by the saturation pressures of the crude oils. Migration of oil into the Kingfish and Halibut fields apparently took place no later than 10 to 24 m.y.B.P. Gas migration into Marlin and associated gas fields took place later. There is evidence that oil and gas is forming at present, leading to the conclusion that both old and new oil exist in the basin.
ROBE RIVER — AN ONSHORE SHALLOW OIL ACCUMULATION
Authors: Thomas B. M.
Published: August 2017

Aeromagnetic depth-to-basement estimates made in 1966 led to the concept of the "Robe River Embayment", a structural depression related to a block of Palaeozoic sediments which has been douwnfaulted into the Precambrian in the northeastern corner of the onshore Carnarvon Basin. During a subsequent seismic survey (1966-67), a deep shothole blew out at 77 m. About 20 litres of heavy brown crude oil were recovered, followed by a strong artesian water flow. The search for a shallow oil accumulation followed with a programme of nine coreholes in 1967-68. Shows of oil and gas were encountered in seven of the wells, but producibility was not established. Further drilling in 1969 (one well), 1972 (five wells) and 1974 (two wells) has better defined the area of hydrocarbon occurrence, but no significant tests have resulted despite promising shows in many of the wells.Robe River oil is of low gravity (14.5 to 20° API), highly aromatic, and biodegraded. It is found at depths ranging from 65 to 165 m mainly within the low-permeability Mardie Greensand. The greensand is underlain by the highly permeable Yarraloola Conglomerate which is an artesian aquifer and has probably acted as the main conduit for oil migration out of the Barrow Sub-basin. There is no evidence of major structural control on the Robe River oil shows which occur sporadically over a large area. Whilst permeability barriers within the Mardie Greensand probably influence the present distribution of hydrocarbons, there is also evidence that the hydraulics of the Yarraloola Conglomerate have been important in the localization of this accumulation. Water salinity studies suggest that the influx of meteoric water from the Yarraloola Conglomerate outcrop has resulted in a hydrodynamic trap for oil as it migrated updip from the Barrow Sub-basin. During the late Tertiary a much larger accumulation may have existed within the Yarraloola Conglomerate and the Mardie Greensand. The northwesterly flow of water has now ceased and the oil has dispersed, except where it is trapped within the relatively impermeable Mardie Greensand.
THE GEOLOGY AND EVOLUTION OF THE SCOTT PLATEAU
Authors: Stagg H. M. J.
Published: August 2017

The Scott Plateau and the adjacent Rowley Terrace cover about 130,000 km2 beyond Australia's Northwest Shelf in water depths ranging from 300 m to 3000 m. The regional geology and structural evolution of the area have been interpreted from about 13,000 km of seismic reflection profiles.The Scott Plateau forms a subsided oceanward margin to the Browse Basin. For much of the period from the Carboniferous to the Middle Jurassic, preceding the breakup which formed this part of the continental margin, the Scott Plateau was probably above sea level shedding sediment into the developing Browse Basin. After breakup in the Bathonian to Callovian, the plateau subsided, until by the Late Cretaceous open marine conditions were prevalent over most of the area, with the probable exception of some structurally high areas which may have remained emergent until early in the Tertiary. Carbonate sedimentation commenced in the Santonian and has continued to the present, with major hiatuses in the Paleocene and Oligocene. Analysis of magnetic and seismic data indicates that, over much of the plateau, economic basement of possible Kimberley Block equivalents is probably no more than 3 to 4 km below sea bed. To the south of the Scott Plateau, the Rowley Terrace is underlain by a wedge of at least 6 km of Mesozoic and Tertiary sediments of the northeast- trending Rowley Sub - basin. The Rowley Sub -basin connects with the Beagle Sub-basin to the southwest and probably connects with the Browse Basin to the northeast. It has been largely unaffected by episodes of faulting, except in the southwest where faulting and folding are pronounced. The petroleum potential of the Scott Plateau is not rated highly. The potential hydrocarbon-bearing sediments here are probably no younger than Palaeozoic. These are quite likely to be only 2 to 4 km thick, and any hydrocarbons generated within them would probably have been lost during the protracted period of emergence and erosion that preceded breakup. The hydrocarbon potential appears to be greater in the Rowley Sub-basin, where Triassic to Cretaceous shale and siltstone source rocks, and Triassic to Lower Cretaceous sandstone reservoir rocks are expected to be present. However, the potential of these sequences is downgraded because hydrocarbon shows in exploration wells on the adjacent part of the Northwest Shelf have been only minor, and by the apparent scarcity of suitable traps. Exploitation of any hydrocarbons would be costly owing to the great water depths.
SHELL'S OFFSHORE VENTURE, IN SOUTH AUSTRALIA
Authors: Whyte R. K.
Published: August 2017

Offshore South Australia permit O.E.L. 38 was granted to Shell Development (Aust.) Pty. Ltd. on 1st January 1966. An aeromagnetic survey of 10,300 km, three seismic surveys totalling 10,300 km and five man months of coastal field work were carried out before the permit was reissued at the end of 1968 as three separate permits SA-5, SA-6 and SA-7 under the newly enacted joint offshore legislation. At that time Shell also secured two adjoining deep Water permits SA-10 and SA-11.In the period 1969-70 two seismic surveys totalling some 11,750 km were shot. Given geophysical results, a six well drilling programme was planned to commence early 1972. Two dry wells, Platypus-1 and Echidna-1 were drilled in early 1972 in SA-6 and SA-7, with Platypus-1 providing some geological encouragement.Several more prospects were found in SA-6 and SA-7 by the 1973 and 1974 seismic surveys, but these were so small that further work could not be economically justified. SA-6 and SA-7 were surrendered in late 1975 without further wells being drilled. Potoroo-1 was drilled in early 1975 in SA-5. It severely downgraded the prospectivity of that permit, leading to early relinquishment later in 1975, but provided vital geological information relevant to permits SA-10 and SA-11 where drilling was due to commence in 1978. A detail seismic survey in the latter two permits was shot in 1976. Prior to 1976, the main incentive for exploration of the deepwater play had been the apparent presence of a very large anticlinal trend in the central part of SA-10. Interpretation of the 1976 survey showed this trend to be non-prospective, and as a result SA-10 and SA-11 were relinquished in April, 1977. This ended a venture in which three wells were drilled and 24,546 km of seismic data recorded for a total expenditure of $15,837,000.
REGIONAL LITHOFACIES AND PALAEOGEOGRAPHY OF THE GIDGEALPA GROUP
Authors: Thornton R. C. N.
Published: August 2017

The Permian Gidgealpa Group contains major reserves of gas and minor amounts of oil in fluvial to marginal marine sandstone reservoirs within coal measures in the Southern Cooper Basin. Lithofacies analysis of a sequential set of palynologically defined time-rock units through the Gidgealpa Group has clarified depositional trends, identified regions of maximum channel development, located positions of shore-lines and shown directions of marine transgressions and regressions.Braided streams deposited the oldest unit, the Tirrawarra Sandstone, on a possibly glacially scoured land surface. As topographic gradients declined, rivers began to meander, and sandstone, shale and coal deposits of the Patchawarra Formation encroached over Tirrawarra Sandstone. Northwards flowing rivers gradually filled pre-Permian valleys with detrital sediments.During uppermost Patchawarra Formation deposition, the Cooper Basin was invaded from the east by a restricted sea, which then deposited the Murteree Shale. As this sea retreated, shoreline sediments of the Epsilon Formation prograded towards the east. A second transgression inundated the land, and the Roseneath Shale was deposited. Finally, delta deposits forming the Daralingie Beds prograded eastwards in the wake of the retreating sea.A period of erosion followed, during which time the present structural grain was imposed on the basin. Subsequently, eastward flowing meandering rivers deposited sandstone, shale and coal of the Toolachee Formation on an essentially flat topography, with only minor hills. The Toolachee Formation grades upwards into non -coal bearing beds, which perhaps register a climate change.
USE OF SMALL CHARGE SOURCES IN THE JUNGLE SWAMPS OF PAPUA NEW GUINEA
Authors: Criss I. F.
Published: August 2017

Seismic field operations are always difficult to conduct but problems multiply greatly when operating in heavy jungle swamp environments. Esso Papua New Guinea recently concluded an onshore seismic program in the Fly River delta of Papua New Guinea. This paper discusses methods employed to operate in this extremely hostile environment to obtain reasonable quality seismic data at an acceptable price. A novel shooting technique which had a profound affect on quality of data, speed of recording and overall cost, is discussed.