bluuebunny/crossref_metadata_2025 huggingface dataset:
THE GRAVITY FIELD AND STRUCTURE OF PAPUA AND NEW GUINEA
Authors: St. John V. P.
Published: August 2017

Interpreted in the light of existing geological knowledge a regional gravity survey of eastern New Guinea defines the major tectonic units of the area and clarifies its tectonic history. At least 7000 metres of Mesozoic sediments are present in a basin extending from the Aure Trough to West Irian, but reaching its maximum development in the Southern Highlands area. To the south and west of tlfis basin the Fly River platform exhibits an undulating basement resulting from northwest-towest-trending faults or flexures of Lower Cretaceous age. The Kubor Range, forming part of the northern margin of the Southern Highlands basin, appears to have been an intermittently-positive area since the early Mesozoic. Anomalies over the Papuan Ultrabasic Belt are consistent with the origin of this body as a thrust of subcrustal material from the northeast. Originating during the Cretaceous the thrust uplifted metamorphics overlying the ultrabasics, and this rising land northeast of the present Owen Stanley Range provided a source for thick Tertiary sedimentation in the Aure Trough. Transcurrent faulting in the Cape Vogel area separates the small and rising Cape Vogel Basin from the Northern Papuan Basin over the subsiding northeastern edge of the ultra-basic belt. More than 8000 metres of Miocene and younger sediments are present in a basin extending from the Markham valley through to the lower Sepik, the sediments being uplifted by thrusting in the Adelbert, Finisierre and Saruwuged Ranges. The sedimentary section through the Sepik valley is generally less than 3000 metres, with local increases to about 5000 metres in the Nuku Basin and to a possibily greater depth in the Upper Sepik August Rfver Basin.(somatic and free-air anomalies indicate that a zone of isostatic and tectonic instability extends the length of the northern coast of eastern New Guinea. To the south and east of this zone, which is generally less than 150 kilometres wide, the Owen Stanley block, the central highlands and the southern platform are in a state of much greater stability. This present distribution of stable and unstable regions lends support to the concept of the evolution of New Guinea as a series of orogenic zones developing on, and becoming incorporated in, the northeastern margin of the Australian continent.
EXPLORATION IN THE AUSTRALIAN TRUST TERRITORY OF NEW GUINEA
Authors: Tailard C. A.
Published: August 2017

Petroleum exploration in the Australian Trust Territory began in 1921 as an extension of thé surveys being conducted in Papua by Anglo Persian for the Australian and British Governments. Following an interruption during and after the Second World War. the present phase of petroleum exploration began when Permit 41, New Guinea. was issued on 10th January, 1965. Recent geologic explorations on Permit 41. New Guinea and on Permit 48, New Ireland and New Britain, has added new geologic data that has led to the use of more sophisticated geophysical tools in the Ramu River and Sepik River areas and has moved the exploration activities toward a more mature stage of development.
THE GEOLOGY OF THE OFFSHORE CANNING BASIN, WESTERN AUSTRALIA
Authors: Challinor A.
Published: August 2017

The Canning Basin is a major geological province of Western Australia and of the Australian continent. It constitutes a major crustal down-warp between the Precambrian Kimberley and Pilbara Blocks and extends offshore onto the wide Rowley Shelf. A large part of this shelf is held under petroleum exploration permit by a group of companies of which B.O.C. of Australia Limited is operator.To date no wells have been drilled in this offshore Canning Basin but extensive geophysical surveys have allowed an interpretive geological model to be presented. This model is based upon an interpretation of geophysical data by extrapolation from offshore data and well control in the Carnarvon Basin and onshore well, outcrop and geophysical data in the Canning Basin.The major Palaeozoic structural features of the Broome Swell and Fitzroy Graben which characterise the onshore Canning Basin extend offshore beneath Mesozoic and Tertiary cover. Thick Palaeozoic and Permo-Triassic sediments are thus expected offshore in the Fitzroy Graben extension and in a major sub-basin at the offshore margin of the Pilbara Block called the Bedout Sub-basin. This sub-basin is believed to have had continued development during the Mesozoic with the accumulation of large thicknesses of Jurassic-Cretaceous sediments. It is restricted further offshore by the structurally positive Rankin Platform, a feature reflected in a large positive gravity anomaly.Mesozoic deposition was associated with a westerly tilt of the Rowley Shelf and Mesozoic thickness consequently increases westwards. The tilt increased during the Tertiary with the development of a major Tertiary stratigraphic wedge locally reaching 8000-10,000 feet in thickness at the shelf edge.Sedimentary deposition was controlled throughout Phanerozoic time by periodic epeirogenic warping related to uplift of the two major blocks. These movements caused considerable structural fragmentation and initiated periods of exiensive erosion. Complex lithofacies variations are thus expected and multiple intra-sectional unconformities are evident.The area contains many fault induced fold features, some compressional folds and extensive stratigraphic trap potential. Coarse clastic units with high hydrocarbon reservoir potential are expected to occur in close association with postulated marine Mesozoic basinal shale sequences. Similar deposits in the Carnarvon Basin and its offshore extension have been proved to be hydrocarbon bearing and productive (Barrow Island). The hydrocarbon potential of the offshore Canning Basin is thus rated highly.
EVALUATION OF THE WINDALIA SAND, BARROW ISLAND AN EMPIRICAL APPROACH
Authors: Burdett J. W. , Parry J. C. , Willmott S. P.
Published: August 2017

The Barrow Island oilfield derives 97 percent of its 46,000 barrels per day production from the Lower Cretaceous Windalia Sand. The lithology of the sand, which is 110' + 20' thick across the field, is very finegrained, glauconitic sandstone, shaly and silty in parts and varying from moderately unconsolidated to firm. Thin, hard beds of dolomitic and calcareous, sandstone occur throughout. The sand has high porosity and low permeability.The argillaceous and unconsolidated nature of the formation precludes the use of log interpretation methods based on standard parameters, and it was decided to develop an empirical log evaluation method. In order to calibrate the logs, sixteen of the early wells were fully cored and logged, and the data compared using the Holgate method, which allows two parameters to be correlated to determine their relationship. In the example which is the subjert of this paper, core porosity was correlated against both sonic transit time and bulk density and hence calibration of these log parameters was obtained.The best fit straight line relating porosity and sonic transit time has its origin at 76 microseconds per foot and extrapolates to 246 microseconds per foot at 100 percent porosity. The bulk density — porosity cross plot gives a grain density of 2.71 grams per cubic centimetre and fluid density of 1.16 grans/ cc. The deviations from the standard parameters of delta-t matrix = 56. delta-t fluid = 189, grain density = 1.65, fluid density = 1.0 are explained by the shaliness and lack of compaction of the formation. Using charts for the calculation of water saturation and porosity from induction conductivity and sonic transit time (or bulk density) at 2' intervals through the sand, backed up with traced SP and caliper curves, an evaluation plot of standard format is developed. Intervals of nett effective pay are then chosen.Other evaluation techniques used during the development of the Windalia Poo! include a modified movable oil plot, used in the water injection wells where a saturated saline drilling fluid was employed, and a Sonic-Neutron log comparison for the identification of suspected gas columns in the Windalia.440 wells have now been drilled at Barrow Island, and the empirical evaluation methods evolved have enabled the definition of beds of producible hydrocarbons in all cases.
ISLAND DRILLING OPERATIONS OFFSHORE CARNARVON BASIN
Authors: Ingram E. N. , Shields Wayne S.
Published: August 2017

Oil was discovered in Cretaceous and Jurassic age sands in Barrow Island No. 1 well in June 1964. As a result the need for broad regional stratigraphic control within the Barrow sub-basin of the Carnarvon Basin became urgent.Barrow Island is located 40 miles off the north-west coast and 65 miles from Onslow.Investigation showed a number of islands suitably located to provide sites for drilling to obtain stratigraphic information if problems of transportation, access, and rigging up in loose beach sand could be economically solved.Detailed planning resulted in the choice of shallow draft landing barges for transport and tracked vehicles and trailers for movement from the barges to the drill sites. A contract was let for the supply of a new self propelled drilling rig specially rigged up for the anticipated conditions. While equipment was being mobilized a detailed survey of beaching conditions on all islands considered to be candidates for drilling, was completed.The first well was spudded on September 21, 1966 on Long Island, 70 miles south-west from Barrow Island and the last well, Stokes Point No. 1 on the southern end of Barrow Island, was completed June 16, 1968. The total program comprised 15 wells with a total footage drilled of over 98,000 feet.
MOORING FLOATING OIL RIGS - NORTHWEST AUSTRALIA
Authors: Stroud S.
Published: August 2017

B.O.C. of Australia Limited has drilled five wells on the continental shelf of Northwest Australia using floating type oil exploration vessels. To date three different methods of anchoring have been used in the Group's operations depending on the type of sea bottom encountered and the progress of technology.On coral and shoal areas south of Timor good anchoring ground has been located. Both drilling exploration vessels S.S. "Glomar Tasman" and the "Investigator," a drilling barge, have been anchored in this area using all chain anchor systems.Three wells have been drilled in an area approximately 100 miles northeast of Barrow Island where surveys revealed smooth limestone sea beds of such hardness that conventional ships anchors could not penetrate the surface to obtain a firm hold. Anchor pilings to hold the "Glomar Tasman" have been successfully installed on the sea floor at two drill sites using a small vessel, M.V. "Nyhavns Rose," of 400 tons. These piles were drilled into the sea bed using a drill string and a power swivel at the surface, and utilizing a counter weight system to allow for vessel heave. At the first locality, in 180 feet of water, divers were used to manually connect the heavy pendant wires to the anchor piles. At the second location a diverless method of installing drilled in anchor piles with chain mooring pendants attached was designed and successfully used in a water depth of 265 feet.
TIDES, WEATHER AND SURFACE DRIFT IN BASS STRAIT
Authors: Brodie Robert , Radok Rainer
Published: August 2017

The Centre's growing interest in social implications of oceanography has found a welcome outlet in a field study of the transport processes on the continental shelf in Bass Strait, using the B.H.P. - Esso operating platforms as base. The first few months of this work, its results and the lessons learnt from it are described with some detail. It is shown that extensive observations with sophisticated equipment would permit exploratory studies at the planning stage of industrial, including nuclear power plants, sewerage outlets, shipping terminals, etc., with a view to ensuring conservation of the environment.
EVALUATION OF LARGE AREAS OF A SEDIMENTARY BASIN
Authors: Condon M. A.
Published: August 2017

A quantitative basis for evaluating exploration acreage can be provided at all stages of petroleum exploration.Treating each main sedimentary sequence separately, the volume of sediments concerned is calculated or estimated, and factors based on industry experience and personal judgement are applied to this volume of generated, movable, trapped, discoverable, and producible hydrocarbons, expressed as oil.The present value of these inferred reserves is calculated by assessing the likely profit per barrel (in the local situation) and discounting this over the likely period before half of the reserves are produced.From the present value, the maximum economic expenditure on land acquisition plus exploration can be indicated.As exploration proceeds, new information can be used to revise the estimate of inferred reserves and, if the economic environment changes, the current value can also be revised.Particularly where land acquisition is costly such economic assessment can place proper limits on the price payable for land at all stages of exploration and thus avoid the situation where production success is not followed within a reasonable period by profitability.
THE USE OF THE SEISMIC REFRACTION METHOD IN PAPUA
Authors: Laws M. J.
Published: August 2017

Among the advances in geophysical techniques during the past ten years, particularly those related to multiple coverage using the seismic reflection method, the seismic refraction method has become somewhat neglected. The neglect has often been necessary since the seismologist is increasingly required to detail more complex structures and locate hydrocarbon bearing features that have been formed by subtle variations in stratigraphy or lithology, refinements that cannot be produced by the refraction method.However, the refraction method has been used with success in areas where the primary drilling target is an interface at which there is a large increase in seismic velocity, such as in Iran where the Asmari limestone provides a good refraction horizon. Similar conditions exist in Papua where the Miocene limestone was an early target and it was with expectation of similar success that the Australasian Petroleum Company, with the Anglo Iranian Oil Company (which later became BP) as a partner, embarked on a programme of refraction exploration in Papua. Early surveys, planned before the nature of the limestone structures was fully understood, failed to provide satisfactory structural information, but as the programme progressed and expanded a pattern of refractors became recognised.In the Eastern Delta, basement is recorded at depths of over 20,000 feet and an unreliable refractor from within the Miocene is evident. As we move towards the west, the top of the Miocene limestone becomes apparent as a refractor, increasing in intensity as we continue westwards until multiple limestone refractors become evident in the Western Delta area.
THE NATURAL CONVERSION OF OIL TO GAS IN SEDIMENTS IN THE COOPER BASIN
Authors: Brooks J.D. , Hesp W.R. , Rigby D.
Published: August 2017

In the Permian Cooper Basin, South Australia, in which oil and gas occur in coal-bearing sediments, there appears to be a relation between the degree of low grade metamorphism of the coaly matter and the nature of the hydrocarbons in the reservoirs. Liquid hydrocarbons are not found in areas and at depths where the coals are at the high-rank bituminous stage (88-89% carbon, dry mineral-free); there, methane is the main hydrocarbon present. Oil occurs in association with coals of lower rank (80-85% carbon, dry mineral-free) and it seems possible that underground gasification of the liquid hydrocarbons has occurred under natural conditions during advanced coalification.In order to test this, mixtures of long chain paraffins (C10-C28) and (C16-C31) from Kingfish crude oil (East Gippsland Basin) were heated at various pressures, with and without water at temperatures between 255-375°C with the intention of reproducing in one week reactions which might occur at lower temperatures in sediments during geological time.The formation of gaseous products (C1-C4 hydrocarbons; hydrogen and carbon dioxide), light liquid paraffins (C10-C16) and aromatic hydrocarbons was observed. The average chain length of the long chain hydrocarbons was reduced and the effect was more pronounced with the longer chain (C16-C31) fraction. It is concluded that during extended time at temperatures near 400°F which prevail in the deeper parts of the Cooper Basin, gasification reactions involving progressive chain shortening could be responsible for the absence of liquid hydrocarbons in regions where the coals are of the high-rank bituminous type.
THE APPLICATION OF GAS PLANT SIMULATION BY COMPUTER TECHNIQUES TO THE GIPPSLAND PLANT START-UP
Authors: Schubert J. M.
Published: August 2017

Start-up of the first portion of the Gippsland Basin Development project was begun in March, 1969, when gas was delivered into Victorian metropolitan markets. The gas and crude producing system which spans a pipeline distance of some 200 miles will ultimately include five offshore producing platforms and two onshore plant complexes capable of producing and processing 400 MMCFD of natural gas, 300,000 BPD of crude oil, fractionating 45,000 BPD of LPG, and terminalling both crude and LPG including marine tanker operations. The major portion of the plant complexes and three of the platforms have been successfully placed in operation to date.Detailed analysis and planning of all aspects resulted in safely placing these facilities in operation at the earliest possible time with maximum safety and minimum lost production. However, inter-relation of multi-product commitments for natural gas, ethane, LPG and stabilized crude oil compounded the burden of the segmented system start-up, necessitating prompt and frequently overlapping start-up of more than one segment at a time. Furthermore, initial conditions were necessarily quite different from design.Throughput of crude was in the order of 100,000 BPD with significantly different properties from the mix ultimately expected. The gas absorption plant was initially operated with a throughput of approx. 25 MMSCFD, some 8 percent of design. To provide process set points and optimize start-up procedures, computer simulation models of each of the plants were made, and the results integrated into a comprehensive plant start-up plan.This presentation will discuss the simulation techniques used, together with the development and application of the start-up plan.
NATIONAL AND STATE BENEFITS FROM OFFSHORE PETROLEUM
Authors: Hunter A.
Published: August 2017

A simulated cash flow for three sizes of offshore field (100 MMB, 250 MMB and 1,000 MMB) can be made for a 20 -year period. The objective is to estimate not only the revenues of the producer but also to derive the probable expenditure patterns in the National and State economy and the flow of tax moneys to the respective governments.On the values selected the 100 MMB field would not be produced if the company gave proper importance to the result of the discounted-cash-flow exercise. For the 250 MMB field the governments' share of royalty and company tax would be 31 per cent of the gross value of the barrel (at an Australian supply price of $2.06); while for the 1,000 MMB field the share would be 36 per cent. These are conservative estimates of the cash flow going into the public purse. Of total expenditures in Australia it seems likely that only 65 per cent are retained in Australian accounts. The rest is import content. In a particular State the retention would be around 20 per cent at the exploration stage in offshore work, 50-60 per cent for development and some 80 per cent for operational expenses. On this sort of figuring a table of direct expenditures, including royalties, can be computed for the State over the whole period. For a 250 MMB field the annual contribution to State spending is significant. It has, of course, multiplier effects also. Labour multipliers, as distinct from income multipliers, are often significant. They are variable depending on the initial development of the region and the contribution offshore oil can make to the regional economy. If close to the capital city the oil field, at all stages, may employ existing engineering services, shipping, supply and labour. New jobs in these supporting services are therefore transfers from other industries if the unemployment rate is low. Thus, for the capital city the job multiplier may be as low 1.03 (3 per cent is the normal rate of growth of the work force) with only minor additions created by oil workers and staff brought in from other States. At the other extreme a discovery on an isolated stretch of coast could require a new port, and port-town development for treatment plant and other oil field services. The job multiplier for the area (number of jobs created for each new one in the oil industry) could well be three or four. In time, and supposing that such a settlement became a port for other traffic, e.g. minerals, and that fuel-and- power-using and chemical industries became attracted to the facilities (consider Port Hedland, Kwinana and Westernport Bay) the regional job multiplier could in time reach a value of 15-20. Offshore oil, in the right location, can be a costless, efficient vehicle for decentralisation policy.
THE RANKIN TREND NORTHWEST SHELF, WESTERN AUSTRALIA
Authors: Kaye P. , Edmond G.M. , Challinor A.
Published: August 2017

Recent gas/condensate discoveries on the Rankin Trend in the southern part of the Northwest Shelf of Western Australia have provided considerable encouragement to exploration effort in Western Australia and have demonstrated that the area could become a major hydrocarbon producing region.The Rankin Trend is located near the outer part of the Dampier Sub-basin, a northern offshore extension of the Carnarvon Basin. Geologically, the Dampier Sub-basin consists of a block-faulted Lower Mesozoic substructure overlain by thick Upper Mesozoic and Tertiary sediments.Thick clastic Triassic and Jurassic sediments were subjected to extensive faulting, which resulted in the formation of several structural trends related to northeast-southwest faults downthrowing towards the present coastline. Later Jurassic and Cretaceous deposition covered this block-faulted substructure with deltaic progradation seaward from the present coastline. Progradation continued through the Tertiary with deposition of up to 10,000 ft. of carbonates and clastics.The Rankin Trend consists of several en echelon fault blocks containing Triassic sediments overlain by Cretaceous and Tertiary shales and carbonates. Structural development continued during the Cretaceous and Tertiary causing differential compaction and drape over the pre-existing features.North Rankin No. 1 was drilled in 401 ft. of water to a depth of 11,593 ft. on a culmination along the trend. The well proved a net Upper Triassic sandstone pay 1020 ft. thick within a gross 1851 ft. thick Upper Triassic column. Drillstem tests flowed up to 14 million cu.ft. per day gas from selected intervals, with an average condensate ratio of 30 bbls. per million cu.ft.A second well, Rankin No. 1, drilled in 303 ft. of water on a separate culmination of the trend some 29 mi. southwest of North Rankin No. 1, proved a similar stratigraphic column and a net 216 ft. of Upper Triassic sandstone pay. A thin basal oil column produced 1062 bbls. oil and 10.9 million cu.ft. of gas per day. The gas reservoir flowed 15.9 million cu.ft. per day with condensate at the rate of 35 bbls. per million cu.ft. A third well, Goodwyn No. 1, on another culmination between the North Rankin and Rankin wells, has proved additional gas/condensate reserves.The Northwest Shelf Group, operated by B.O.C. of Australia Limited, is currently studying the feasibility of commercial hydrocarbon production.
PETROLEUM AND GEOLOGY: A SYNTHESIS
Authors: Chapman Richard E.
Published: August 2017

A marine sedimentary basin typically begins with a transgressive phase and ends with a regressive phase; but there may be several cycles, and also periods in which neither is dominant.Petroleum occurrences fall into two broad stratigraphie classes: those of transgressive sequences, and those of regressive sequences. Transgressions tend to accumulate potential source rocks on top of potential reservoir rocks, and the petroleum tends to migrate downwards then laterally into stratigraphic traps, especially reefs and below unconformities. It also occurs in diachronous units that are anticlinal in form due to basement irregularities. Regressions tend to accumulate potential reservoir rocks on top of potential source rocks, and the petroleum tends to migrate upwards and then laterally into anticlines and fault traps that are typically initiated contemporaneously or penecontemporaneously with sediment accumulation. There is some evidence that oil of transgressive sequences is heavier than oil of regressive sequences.Evidence derived from subsurface geology, including petroleum occurrences, suggests that young marine sedimentary basins are typically deformed by vertical, gravity processes during and just after significant regressive phases of their development; and that these processes are a direct consequence of the accumulation of sediment in a regressive sequence. Subsequent horizontal tectonic events, in general, only modify the earlier, contemporaneous, deformation.
GEOLOGY AND PETROLEUM PROSPECTS OF RUATORIA AREA, EAST COAST, NORTH ISLAND, NEW ZEALAND.
Authors: Laing A.C.M.
Published: August 2017

As measured in outcrop sections, more than 30,000 ft. (9,000 m.) of Upper Cretaceous and Tertiary marine sediments overlie basement of Lower Cretaceous age in the area. Mudstones, siltstones, and turbidites make up the majority of this sedimentary section but there are also 3,000 ft. (900 m.) of interbedded greywacke sandstones and siltstones of Maestrichtian age, and 400 ft. (120 m.) of interbedded limestone and greensands of Oligocene age. Both of these latter units are potential reservoir beds.The majority of the exploration work has been by surface geological mapping. A number of time-rock units have been used which were initially distinguished by fossils, but which could later be distinguished by lithological differences.Four regional unconformities, base of Upper Cretaceous, near top of Upper Cretaceous, Upper Oligocene, and Upper Miocene have been recognised in the stratigraphic section.A slump breccia of Upper Eocene age has also been mapped extending over an area 25 mi. (40Km) by 5 mi. (8Km) with a maximum thickness of 7500 ft. (2.25Km.) and contains large lumps of older rocks. The sediments of the Ruatoria area are folded into broad synclines and tight anticlines with average dips ranging from 50 degrees in the Upper Cretaceous to 15 degrees in the Upper Miocene. The trend of the folds is northeast in the southern part of the area and northwest in the northern part, the dividing line being the major northwest trending Hikurangi Fault.The area abounds in gas seepages some of which have been capped and exploited. There are records of oil seepages also. Within the 453 sq.mi. (1,178 sq. Km) only nine shallow holes have been drilled all of which recorded some oil or gas shows.Alliance Petroleum has located two wells on the flanks of closed structures outlined by surface geology and shallow structure drilling.
THE GEOLOGY OF THE PALCHAWARRA AREA COOPER BASIN
Authors: Kapel A.J.
Published: August 2017

This paper is another chapter in the long series of papers presented to APEA Conferences since 1964 on the geology of the Cooper Basin. The Patchawarra area became of interest after Bridge Oil on behalf of its partners discovered oil in the area while drilling Tirrawarra No. 1 as part of their obligations to earn a 50 percent interest in the area. This paper deals with the central part of the Patchawarra Gravity Low first described by the Author in 1966.The Tirrawarra Formation was deposited in the Patchawarra trough during early Permian. The Gidgealpa Innamincka trend constitutes the eastern boundary of this trough while the western boundary of the Patchawarra Gravity Low coincides with the western boundary of the Cooper Basin.Sedimentation during the Permian in the Cooper Basin is controlled regionally by the major structural trends such as, the Gidgealpa Innamincka Trend, but hiatii and minor local unconformities also developed around individual structrues.The major unconformity recognised in the Patchawarra Low occurs between the Upper Permian Toolachee Formation and the Lower Permian Moomba Formation.
PETROLEUM PROSPECTS, BLIGH WATER, FIJI
Authors: Lindner A.W.
Published: August 2017

The Fiji Archipelago constitutes a segment of the island arc system of the southwest Pacific. The islands in the group comprise a mixture of igneous and sedimentary rocks including carbonates. The hydrocarbon potential of the region has been emphasised since the Tonga oil seepage drew the attention of the oil industry to this part of the globe in 1968.Southern Pacific Petroleum (Fiji) Limited was granted the first offshore petroleum concession in Fiji by the Government in 1969 and the negotiation for the concession resulted in the formulation of Fijian offshore petroleum exploration legislation. Reconnaissance sparker seismic shooting indicated the existence of stratified rocks beneath Bligh Water and subsequent aeromagnetics and multiple coverage seismic has confirmed the presence of a sedimentary basin.The oldest dated sedimentary rocks in Fiji are Eocene. They form part of a very thick sequence, including volcanics, ranging into Lower Miocene which regionally has been mildly metamorphosed. Locally this sequence has been intruded by intermediate to basic plutonic stocks which subsequently have been unroofed by widespread intra-Miocene erosion. This sequence constitutes the economic basement in the region. Middle to Upper Miocene and Pliocene clastic, marine, fossiliferous sediments and shallow water carbonates on the two main islands of Fiji were deposited in localised basins, generally in complex association with volcanic rocks.The sedimentary column contains considerable fine grained, dark coloured, marine elastics. Bioclastic limestone, also present in the sequence, has excellent porosity and permeability. Good reservoir character is similarly indicated for some of the coarser elastics, despite the lack of quartz.The seismic data, when integrated with the geology of the islands, infer that the deepest continuous reflection horizon represents the intra-Miocene unconformity; additionally, the data show that the Bligh Water Basin is divided into northern and southern components, divided by a basement high. The southern region appears more attractive for exploration as 7000 ft. (2100 m.) of section is indicated and the area is covered by shallow water. Faulting and drape features are the obvious structural forms present. Several discontinuous reflection events, commonly occurring at equivalent positions on different seismic profiles, may indicate presence of carbonate banks or cays similar to the type of carbonate deposits exposed in the succession onshore.
EXPLORATION FOR OIL-BEARING SAND TRENDS IN THE FLY RIVER AREA, WESTERN PAPUA
Authors: Conybeare C.E.B. , Jessop R.G.C.
Published: August 2017

The Magobu Island No. 1 well, drilled by Endeavour Oil Company N.L. late in 1970, was located to test a large, northwest-trending, Mesozoic anticline at the mouth of the Fly River, Western Papua. The anticlinal trend was postulated to be coincident with an intra-Mesozoic strand line where massive lenticular sand bodies may have developed.The well penetrated 3,086 ft. of Pliocene and Miocene carbonates and 5,360 ft. of Lower Cretaceous and Jurassic elastics before bottoming in Carboniferous volcanics.Two massive sandstone units of particular significance, one of Lower Cretaceous age at a depth range of 4,265-4,775 ft., and the other of Middle Jurassic age at a depth range of 7,065-7,345 ft. were intersected. These clean, quartzose sandstones have excellent porosity and permeability but are salt-water saturated at the Magobu location.The electric log character, grain gradation, continuous dipmeter information, and depositional environment (determined by interpreting the lithologic sequence and faunal content of the Mesozoic) indicate that these sandstone units consist of northwest-trending barrier bar complexes. The basal member of the upper unit, in particular, is interpreted as having formed a barrier island.The seismic data support this interpretation with respect to both sandstone units. In addition, a second and thicker bar complex of similar trend, situated some 10 mi. down-dip to the northeast under Kiwai Island, is indicated by the seismic data and can be correlated with the upper sandstone unit at Magobu.Structural interpretations of the relationship between the upper barrier bar complexes at Magobu and Kiwai suggest that oil migrating up-dip would be trapped by the structurally lower bar build-up. This conclusion gives a lead to follow-up drilling in the search for oil-bearing sand trends.
OFFSHORE RADIOPOSITIONING SYSTEMS
Authors: Marchai A. William , Longton R.L.
Published: August 2017

With the search for petroleum deposits in the world pushing farther offshore each year, the oil industry has answered the call with the development of dynamically positioned drill ships, hole re-entry techniques, and subsea completions. These developments are helping make deep water oil recovery a reality. Now, more than ever, there is a need for accurate, long-range radiopositioning systems so that deep water surveys and well locations can be conducted with the required accuracy.Radiopositioning systems of the past decade include land-based systems such as Shoran, Raydist, Decca and Toran and the self- contained Satellite and Integrated systems. Recent developments for work in deeper water further offshore include Loran-C in the Range-Range mode and Differential Omega.
LOGISTICS AND COSTS IN LNG OPERATIONS
Authors: Cole N.H.
Published: August 2017

Liquefied natural gas has been used to date as an economical source of supply for peak-load energy demands. It is a premium priced fuel to consumers, but offers the advantage of reducing air pollution in the future.Large gas reserves necessary to sustain LNG operations are remote from the two principal markets of Japan and the U.S.A. Higher prices have been negotiated for gas landed in the U.S.A. than elsewhere, but the increase in world demand is expected to see the cost of LNG landed in Japan at substantially increased levels by 1980.The largest LNG project to date is the supply of 1,500 MMcfd to the U.S.A. from Algeria. Starting after 1974, this will be the second base -load energy application for LNG. This trend is likely to become more common.LNG technology has become highly developed. New tankers have been constructed, the largest contracted to date being of a 750,000 barrel capacity. Provision of tankers will account for approximately one half of the funds necessary to establish any Australian operation.Future LNG demand will be strong, and considerable forward planning is needed. If an Australian commitment to supply LNG is negotiated in 1972, no revenue is likely to flow until 1976 or 1977. Very large capital expenditures are involved, and an extensive amount of long term debt finance will be required.The indicated minimum Australian venture, supplying 500 MMcfd, would consume five trillion cubic feet of reserves over 20 years. At the current Japanese landed prices for LNG, the economics of such a project are viable. With an increase in the scale of operations, or negotiation of the prices to be paid in the U.S.A., an Australian LNG project appears highly profitable.
THE GEOCHEMICAL CHARACTERIZATION OF AUSTRALIAN CRUDE OILS
Authors: Powell T.G. , McKirdy D.M.
Published: August 2017

Australian oils are generally light by world standards. They have API gravities greater than 35°, low sulphur and asphalt contents, and are of paraffinic or naphthenic base. The geochemical similarity of oils from the Bowen-Surat Basin, with the notable exception of the Conloi crude, is most marked in the fraction boiling above 250 °C. Oils from the Cooper, Gippsland and Otway Basins are probably derived from terrestrial organic material, but differ in their degree of maturation as indicated by n-alkane patterns. Samples from the Perth Basin exhibit a similar variation in maturity. In the Carnarvon Basin, the Windalia crude differs from those in deeper reservoirs in containing a higher proportion of oxygen-bearing, nitrogen-bearing, and sulphur-bearing compounds, another sign of a less mature oil. The East Mereenie oil displays an odd-even predominance in its n-alkane distribution which is characteristic of some Lower Palaeozoic crudes. A Papuan Basin condensate is the only available sample produced from a limestone reservoir. This probably accounts for its higher sulphur content. Two seeps obtained from the Papuan Highlands are inspissated residues which may have suffered microbiological alteration.A major control of the composition of Australian crude oils appears to be the depositional environment of the source rock. Most of the oils show evidence of having been generated, at least in part, from terrestrial (as opposed to marine) organic matter. The location of all but one of the reservoirs within sequences dominated by the sandstone - shale association is consistent with the likely contribution of land plant detritus to their source environment. Likewise, low sulphur and asphalt values reflect the scarcity of favourable carbonate-evaporite source and reservoir situations in Australia.
HYDROCARBON POTENTIAL OF THE MESOZOIC AND BASAL TERTIARY OF THE GIPPSLAND BASIN: A STRATIGRAPHIC ANALYSIS
Authors: Haskell T. R.
Published: August 2017

A thick sequence of uppermost Jurassic, Cretaceous and basal Tertiary non-marine sedimentary rocks underlies the Gippsland area of Victoria. The older part of this sequence is extensively exposed in the west of the Gippsland area, but elsewhere it is known dominantly from well intersections. Although several hiates are recognised, palynological data indicate that a comparatively complete Cretaceous section can be compiled from this sequence in the Gippsland area.The uppermost Jurassic to Paleocene rocks can be divided into three units. The oldest unit is uppermost Jurassic and Lower Cretaceous in age. It consists of variably compacted greywackes and lithic sandstones, minor arkoses and interbedded siltstones and mudstones. The overlying early Upper Cretaceous and Paleocene units are distinguishable paleontologically and consist of quartzose sandstones, carbonaceous siltstones and mudstones.There is no indication of marine influence on sedimentation present in the microfossil content of any of the palynotogical preparations from samples taken throughout most of the sequence. Several species of microplankton are common in the oldest unit, but they are indicative of the lacustrine conditions under which the unit was deposited.Minor hydrocarbon shows have been recorded from the oldest unit, but the sandstones are characteristically tight. More significant shows have been reported from the two younger units that contain relatively clean sandstones interbedded with siltstones and mudstones. These units possess the greatest economic potential of all of the pre-Eocene rocks of the Gippsland Basin.The structural framework of the region is composed of separate series of north-easterly and easterly trending faults or monoclines and a south-easterly regional dip. Differential movements of blocks defined by this fault-monocline pattern appears to have resulted in erosion of the more prospective early Upper Cretaceous and Paleocene strata from all but two subrectangular areas respectively immediately north and south of Seaspray.
AN AUSTRALIAN GEODATA SYSTEM
Authors: Gahan Michael J.
Published: August 2017

Australia is in a very favourable position to set up a central petroleum industry data system particularly as no regional system is yet in operation. Large accessible computers are already available and other countries' experience ensures that a practical system can be evolved.There are three stages to be contemplated:The data input,Simple retrieval,Retrieval and processing.The first stage involves massive and for the most part, routine work but also includes problems of confidential information and interpretation. The second stage is useful for obtaining statistical information and to facilitate literature search. The third stage is open-ended encompassing automatic well correlations, contour maps, seismic cross-sections, reservoir estimations, etc.The Australian situation requires stage 1 and 2 to be introduced as soon as possible. Stage 3 is not recommended until more subsurface data has been obtained. Instead, a microfilm library of the most requested records could be accumulated.Most operating systems are under-used due to unfamiliarity. This can be overcome by supplying a regular output of information on areas of interest.
EXPLORATION IN THE ARAFURA SEA
Authors: Bailie B. , Page C. , Harrison R. , Roussopoulos G.
Published: August 2017

Geophysical exploration and drilling have delineated four major geological elements in the Arafura Sea. A stable block of relatively thin, seaward dipping Mesozoic and Cenozoic strata is separated by a Mesozoic structural and stratigraphic hinge zone from a mobile block of much thicker sediments. Gentle folding disturbs the Lower Cretaceous strata in the mobile block and along the hinge zone, but has little effect on the overlying Tertiary sediments. A strongly folded and faulted pre-Mesozoic graben is the dominant structural element in the stable block.
PLATE TECTONICS AND THE EVOLUTION OF THE TIMOR SEAR NORTHWEST AUSTRALIA
Authors: Warris B. J.
Published: August 2017

The Browse and Bonaparte Gulf Basins in northwestern Australia contain sedimentary sections which range in age from early Palaeozoic to Recent. These basins developed as a result of the rifting and break up of Gondwanaland into two continents. The sedimentary and tectonic histories of these basins clearly reflect the relative movements of these continents.In pre-Permian times, the earliest postulated rifting may have been early Palaeozoic associated with the north-south separation of Gondwanaland from Eurasia which produced the Tethyan Sea. This was followed by Middle Palaeozoic rifting which affected the Bonaparte Gulf Basin, Fitzroy Graben and perhaps also the Browse Basin.A Late Carboniferous-Early Permian rift valley developed between the Kimberley Block and a western landmass. Alternate marine and fluvio-deltaic deposits characterised sedimentation in this rift valley until Early Jurassic time. Marine transgressions inundated from the north where the rift valley opened into the Tethyan Sea.During the Late Jurassic and Early Cretaceous, the western landmass was detached from the Australian continent along a major right lateral wrench fault. At this time the Indian Ocean Basin appeared as a distinct morphological unit and inundated the Browse Basin. Associated with these movements were the emergence of the Ashmore-Sahul Block and Northeast Londonderry Ridge and the development of the Scott Reef-Buccaneer trend. Marine volcanics at Scott Reef and Ashmore Reef may be related to the formation of new ocean crust.At the end of the Early Cretaceous, tectonic events associated with the complete separation of the western landmass from Australia, resulted in a regional northwesterly tilt of the basin and a major marine transgression.During the Tertiary, Australia moved north, away from Antarctica, and eventually collided with the Southeast Asian and West Pacific oceanic plates. Timor uplifted as a Tertiary melange of Australian sediments behind a north-dipping sub-duction zone along the Timor Trough. The Timor Sea remained relatively stable and was the site of carbonate shelf sedimentation.
DIVERSITY OF ISLAND ARCS: JAPAN, PHILIPPINES, NORTHERN MOLUCCAS
Authors: Murphy Richard W.
Published: August 2017

Modern bathymetric, geophysical, and volcanic studies have revealed a remarkably consistent principal profile for island arcs of the Western Pacific. Examination of surface geology, however, suggests great diversity in the geological development of island arcs. Three island arc complexes show the diversity well: Japan, the Philippines, and the Northern Moluccas.Although Japan appears to have been an island arc in roughly its present configuration only since Early Miocene time, the surface geology indicates that Japan has formed part of the continental margin of Asia at least since Permian and probably Devonian time. Subduction polarity, as displayed in paired metamorphic belts; juxtaposition of continental rise prisms with contemporaneous oceanic suites; and overall tectonic fabric strongly supports belief in the existence of the Pacific Ocean since the Devonian. Hokkaido is a reversed island arc segment which together with Sakhalin is probably a relatively recent addition to the northeast Asian continental perimeter.The Philippines were formed by the Late Oligocene coalescence of at least four island arc-subduction zone complexes into a single archipelagic basin which has remained more or less coherent throughout Neogene time. Although the oldest Philippine fossils are Permian, the island arcs probably did not start to form until Late Cretaceous time. Neogene volcanism, intrusion and sedimentation are thought to be creating a new small continent out of materials that were originally entirely oceanic.Island arc systems flanking the Molucca Sea were born in Late Cretaceous time and now appear to be in a stage of coalescence similar to that of the Philippines in Late Oligocene time. The convergence of two west-dipping and one east-dipping Benioff zones, the existence of a very large negative isostatic gravity anomaly, the outcrop of fossil subduction zones and the existence of short topographic trench segments indicate an active, youthful region of crustal construction.
GEOLOGY OF BARROW ISLAND OIL FIELD
Authors: Crank Keith
Published: August 2017

The Barrow Island oil field, which was discovered by the drilling of Barrow 1 in 1964, was declared commercial in 1966. Since then 520 wells have been drilled in the development of this field which has resulted in 309 Windalia Sand oil producers (from about 2200 feet), eight Muderong Greensand oil wells (2800 feet), five Neocomian/Upper Jurassic gas and oil producers (6200 to 6700 feet), eight Barrow Group water source wells and 157 water injection wells.Production averages 41,200 barrels of oil per day, and 98% of this comes from the shallow Windalia Sand Member of Cretaceous (Aptian to Albian) age. These reserves are contained in a broad north-plunging nose truncated to the south by a major down-to-the-south fault. The anticline is thought to have been formed initially from a basement uplift during Late Triassic to Early Jurassic time. Subsequent periods of deposition, uplift and erosion have continued into the Tertiary and modified the structure to its present form. The known sedimentary section on Barrow Island ranges from Late Jurassic to Miocene.The Neocomian/Jurassic accumulations are small and irregular and are not thought to be commercial in themselves. The Muderong Greensand pool is also a limited, low permeability reservoir. Migration of hydrocarbons is thought to have occurred mainly in the Tertiary as major arching did not take place until very late in the Cretaceous or early in the Palaeocene.The Windalia Sand reservoir is a high porosity, low permeability sand which is found only on Barrow Island. One of the most unusual features of this reservoir is the presence of a perched gas cap. Apparently the entire sand was originally saturated with oil, and gas subsequently moved upstructure from the north, displacing it. This movement was probably obstructed by randomly-located permeability barriers.