bluuebunny/crossref_metadata_2025 huggingface dataset:
RECENT EXPLORATION DEVELOPMENTS IN THE NGALIA BASIN, NORTHERN TERRITORY
Authors: Benbow D. D. , Davidson J. , Mulready J.
Published: August 2017

Petroleum exploration of the Ngalia Basin commenced with the Pacific-American Oil Company's seismic and gravity survey in 1964, followed by geological and geophysical surveys by the Bureau of Mineral Resources (BMR) between 1967 and 1978, and then Magellan's Ngalia seismic and gravity survey in 1971.After a ten year break, exploration resumed with the drilling of the Davis-1 well by a consortium of Australian companies which farmed-in to Magellan's Ngalia Basin Permit (OP165). The well was drilled on the flank of a large east-west trending anticlinal dome outlined by surface mapping and limited seismic coverage, and located near the northern margin of the basin. The section penetrated in the well consists of 1134 m of Carboniferous-Devonian sediments unconformably overlying 479 m of probable Cambro-Ordovician marine sediments, which in turn unconformably overlie approximately 246 m of marine ?Adelaidean sediments, including a basal sequence of dark grey marine shale. Source rock analysis indicates that this latter section may provide a significant source rock potential for the basin. A small gas flow was observed during the course of the well, which was air-drilled to a total depth of 1899 m, bottoming in metamorphics which are tentatively correlated with the Pre-Cambrian Patmungala Beds (?Arunta Block). The current exploration effort is now aimed at:more deeply buried structures in the Naburula Fault Trough, in the western half of the basin, andsub-surface extensions of the Walbiri-Bloodwood Fold Zone, in the eastern half.In both cases a more extensive section of marine Cambro-Ordovician age rocks is anticipated, and the limited geochemical data available suggest that these sediments should lie within the oil window.The Newhaven-Mt Allan Seismic Survey, consisting of 344 km of 12-fold vibroseis coverage was shot in these areas in November-December, 1981, in an attempt to define prospects and leads for evaluation by additional drilling over the next three years. The structures mapped to date include reverse faulted blocks with salt-involvement in the Newhaven area to the west, and "sled-runner" thrusts with a plane of décollement in salt in the Mt Allan area to the east.
VIBROSEIS DOWN THE HOLE
Authors: Frazer J. T.
Published: August 2017

A variety of problems associated with the Vibroseis® source have been encountered over the past few years which have presented difficulties in tieing surveys using different control systems and in depth mapping.Accurate depth structure mapping and field estimation from seismic data requires good correlation of seismic reflections with stratigraphic boundaries. The information required, a known seismic signal and vertical rock velocities can only be obtained from measurements down the hole.Seismic time to depth correlation can be obtained from an integrated sonic velocity curve tied to conventional well shoot data only if the source is the same as that used for the reflection seismic data or the relation between the well shoot and seismic source is known. It has been apparent for some time that the signal from the Vibroseis source has not been adequately defined from surface measurements.A number of parameters must be monitored to ensure that the signal transmitted during a Vibroseis sweep is properly calibrated. The synchronisation of phase, time duration of the sweep, sweep bandwidth, vibrator drive levels and the phase relation of the pilot sweep to the signal transmitted from the baseplate, contribute to determine the character of the signal seen on a seismic section.®Trademark of Conoco, Inc.
HYDROCARBON GENERATION IN THE AMADEUS BASIN, CENTRAL AUSTRALIA
Authors: McKirdy K. S. Jackson D. M. , Deckelman J. A.
Published: August 2017

The Proterozoic to Devonian Amadeus Basin of central Australia contains two hydrocarbon fields — oil and gas at Mereenie and gas at Palm Valley, both within Ordovician sandstone reservoirs. Significant gas and oil shows have also been recorded from Cambrian sandstones and carbonates in the eastern part of the basin. The hydrocarbon generation histories of documented source rocks, determined by Lopatin modelling, largely explain the distribution of the hydrocarbons. The best oil and gas source rocks occur in the Ordovician Horn Valley Siltstone. Source potential is also developed within the Late Proterozoic sequence, particularly the Gillen Member of the Bitter Springs Formation, and the Cambrian.Consideration of organic maturity, relative timing of hydrocarbon generation and trap formation, and oil/source typing leads to the conclusion that the Horn Valley Siltstone charged the Mereenie structure with gas and oil. At Palm Valley, only gas and minor condensate occur because the trap was formed too late to receive an oil charge. Differences in organic facies may also, in part, account for the dry gas and lack of substantial liquid hydrocarbons at Palm Valley. In the eastern Amadeus Basin, the Ordovician is largely absent but Proterozoic sources are well placed to provide the gas discovered by Ooraminna 1 and Dingo 1. Any oil charge here would have preceded trap development.
NATURAL GAS — THE AUSTRALIAN INCENTIVE
Authors: Branson J. D.
Published: August 2017

In recent years finding natural gas in Australia has been worth little more than a dry hole. However, establishment of a centralized buying authority with unitary pricing at, or below, today's levels in conjunction with an independent transmission authority could change that.A capital outlay of approximately A$5 billion (1983 dollar) would be required to establish 5000 km of new nationwide gas transmission lines. Funds for the construction would be raised through issuance of inflation-indexed 30-year bonds, retired by transmission revenues and royalty assignments. Social benefits would arise from the approximately 8500 jobs created by the system's construction and a flow-through of up to 35 000 jobs in related industries subsequent to 1990.When the delivery system was in place adequate demand and supply would be assured by virtue of a pricing system which is based upon the encouragement of the 'export substitution' of other forms of primary energy, as well as energy by-products. At a consumer price level of A$5.25 per gigajoule, inclusive of transmission costs of A$3.00 per gigajoule, an increase of 60 petajoules per annum in excess of current consumption estimates of 400 petajoules per annum would be sufficient to render the system economic. Necessary increases in natural gas demand would come from electric plant conversions, primary manufacturing energy conversions, motor transport conversions, export of chemical derivatives, etc. Thus, the more readily transportable, hence marketable, primary energy sources — coal and crude oil — would have a market effect on the balance of payments/trade position.Thus, we take an 'excess' energy form in a nation which today is still dependent upon outside sources of liquid fuels and convert it to an 'energy independence' form, while creating simultaneous nationwide social benefits.
PETROLEUM OCCURRENCE IN THE GIPPSLAND BASIN AND ITS RELATIONSHIP TO RANK AND ORGANIC MATTER TYPE
Authors: Smith G. C. S , Cook A. C.
Published: August 2017

Coal rank, sediment age and downhole temperature data indicate that the rates of burial and palaeothermal gradients in the Gippsland Basin have varied both areally and with time over the Late Cretaceous to Recent period. The generation and occurrence of petroleum are controlled mainly by the burial metamorphic history. The inshore areas are gas prone because the Late Cainozoic burial meta-morphism is moderate and overprints an earlier phase of substantial burial metamorphism in the Late Cretaceous-Early Tertiary. The areas offshore in the Central Deep are oil prone because the earlier burial metamorphism was minor and the burial metamorphism during the last 20 Ma has been rapid and substantial.Vitrinite reflectance values (R̅vmax) vary from about 0.2 per cent at near-surface depths to over 1.2 per cent in the Upper Cretaceous sediments at depths of about 4 km and more. Exinite reflectance values (R̅emax) are about 0.05 per cent at near-surface depths increasing gradually to only 0.15 per cent at 3 km. Significant exinite metamorphism is evident at depths between 3 and 4 km, with major exinite metamorphism at 4-5 km and more at the base of the Upper Cretaceous sequence.The proportion of organic matter and its specific generative capacity increases up through the Latrobe Group. The Late Cretaceous to Early Eocene organic matter consists of orthohydrous vitrinite and diverse inertinite and is distinct from the Middle to Late Eocene coaly matter which consists of perhydrous vitrinite and minor amounts of inertinite. The Oligocene to Miocene organic matter is dominated by perhydrous vitrinites and is inertinite-poor. The overall proportion of exinite is roughly constant up through the Upper Cretaceous to Miocene terrestrial sequences although some forms of alginite are more common in the Eocene to Miocene sediments. Petrographic and geologic evidence suggests that much of the petroleum probably is generated from vitrinite in addition to exinite at low coal ranks (R̅vmax 0.4-0.8 per cent) and low burial depths (2-4 km).
CONODONT COLOUR ALTERATION, THERMAL MATURATION AND THE GEOTHERMAL HISTORY OF THE CANNING BASIN, WESTERN AUSTRALIA
Authors: Nicoll Robert S. , Gorter John D.
Published: August 2017

Examination of conodont colour alteration (CAI) in samples from more than 40 petroleum exploration wells and extensive outcrop collections along the northern margin of the Lennard Shelf forms the basis for a study of the thermal maturation and geothermal history of the Canning Basin of Western Australia. The thickness of the measured CAI intervals is variable and does not conform to the 1200 m standard of the Appalachian Basin. The CAI interval 1 is thick and indicates a low geothermal gradient in the basin but CAI intervals 1.5 and 2 are thin and indicate higher geothermal gradients. A major thermal event of Miocene Age, associated with the intrusion of the Fltzroy Lamproites in the Fitzroy Graben and Lennard Shelf, may be the source of the increased heat flow and also explain an area of high heat flow in some parts of the Graben and shelf.Using the vertical and horizontal distribution of trends of the CAI intervals it is suggested that over large areas of the basin the oil generation window is restricted to an interval about 1100 m thick and, except where migration has taken place, that liquid hydrocarbons will be restricted to the interval between 1600 and 3000 m. In areas affected by the intrusion of the Fitzroy Lamproites, the top of the oil generation window may be as shallow as 800 m.
THE TIRRAWARRA SANDSTONE AND MERRIMELIA FORMATION OF THE SOUTHERN COOPER BASIN, SOUTH AUSTRALIA — THE SEDIMENTATION AND EVOLUTION OF A GLACIOFLUVIAL SYSTEM
Authors: Williams B. P. J. , Wild E. K.
Published: August 2017

An extensive sedimentological study of cores from the Permian Gidgealpa Group of the southern Cooper Basin has produced a new understanding of the relationship between the Tirrawarra Sandstone and the Merrimelia Formation. These two sequences were previously considered to be everywhere separated by a regional unconformity. This study has shown that the facies states, transitions and associations of both formations interdigitate so that typical 'Tirrawarra- type' fluvial deposits are present within glacigenic 'Merrimelia-type' sediments.The Merrimelia Formation was examined regionally in 29 cored wells. Typical facies occurring within the Formation include glaciofluvial outwash, extensive developments of subaerial and subaqueous diamictites, glaciolacustrine ripple-laminated sandstones and siltstones, and thick, monotonous mudrock sequences with clay-dominant rhythmite horizons.The Tirrawarra Sandstone was also examined regionally in 32 cored wells. Four major facies associations were identified within the Sandstone and indicate the temporal and spatial evolution of a fluvioglacial to predominantly fluvial depositional system. Locally the interrelationship between the Tirrawarra Sandstone and the Merrimelia Formation is clearly evident where basal outwash fan deposits of the Tirrawarra Sandstone are interbedded with typical Merrimelia lithotypes. The dominant, low-sinuosity fluvial channel sand facies of the Tirrawarra Sandstone is also an integral part of typical Merrimelia sediment patterns.The Merrimelia Formation and Tirrawarra Sandstone sediments are intimately related and illustrate the evolution of a predominantly glacigenic system into one in which fluvial processes dominate both in time and space. It is evident that no unconformity separates the two sequences and the inclusion of the Merrimelia Formation within the Gidgealpa Group is proposed.A distinct sedlmentological and stratigraphic identity has been assumed in evaluations of the hydrocarbon potential of the Tirrawarra Sandstone. The Merrimelia Formation has been considered generally non-prospective. This study indicates that potential exists for additional reservoirs of 'Tirrawarra type' to be locally developed within the Merrimelia Formation.
HYDROCARBON GENERATION, MIGRATION AND ENTRAPMENT IN THE JACKSON-NACCOWLAH AREA, ATP 259P, SOUTHWESTERN QUEENSLAND
Authors: Mortimore P.W. Vincent I.R. , McKirdy D.M.
Published: August 2017

The northern part of the Naccowlah Block, situated in the southeastern part of the Authority to Prospect 259P in southwestern Queensland, is a major Eromanga Basin hydrocarbon province. The Hutton Sandstone is the main reservoir but hydrocarbons have been encountered at several levels within the Jurassic-Cretaceous sequence. In contrast, the underlying Cooper Basin sequence is generally unproductive in the Naccowlah Block although gas was discovered in the Permian at Naccowlah South 1. Oil and gas discoveries within the Eromanga Basin sequence are confined to the Naccowlah-Jackson Trend. This trend forms a prominent high separating the deep Nappamerri Trough from the shallower, more stable northern part of the Cooper Basin.The Murta Member is mature for initial oil generation along the Naccowlah-Jackson Trend and has sourced the small oil accumulations within this unit and the underlying Namur Sandstone Member. The Birkhead Formation is a good source unit in this area with lesser oil source potential also evident in the Westbourne Formation and 'basal Jurassic'. Source quality and maturation considerations imply that much of the oil discovered in Jurassic reservoirs along the Naccowlah-Jackson Trend was generated from more mature Jurassic source beds in the Nappamerri Trough area to the southwest. Maturation modelling of this deeper section suggests that hydrocarbon generation from Jurassic source units commenced in the Early Tertiary. Significant oil generation and migration has therefore occurred since the period of major structural development of the Naccowlah-Jackson Trend in the Early Tertiary. This trend, however, has long been a major focus for hydrocarbon migration paths out of the Nappamerri Trough as a result of intermittent structuring during the Mesozoic. Gas reservoired in Jurassic sandstones at Chookoo has been generated from more mature Jurassic source rocks in the deeper parts of the Nappamerri Trough.Permian sediments in the Nappamerri Trough area are overmature for oil generation and are gas prone. Gas generated in this area has charged the lean Permian gas Field at Naccowlah South, along the Wackett-Naccowlah- Jackson Trend. North of this trend Permian source rocks are mainly gas prone but more favourable levels of maturity allow the accumulation of some gas liquids and oil. However, geological and geochemical evidence suggests that Permian sediments did not source the oil found in Jurassic-Cretaceous reservoirs in the Jackson- Naccowlah area.
NITROGEN/HELIUM LEAK DETECTION USED ON NORTH RANKIN 'A' PLATFORM
Authors: Albers B. , Rose H.
Published: August 2017

In the past, leaks were found by pressuring the process systems first with water and then with hydrocarbons. This low cost but hazardous method of leak detection used gas detectors and soapy water to detect gas leaks. The disadvantage of this method is that large leaks contaminate the environment, risk a possible explosion and fire, and can result in a considerable loss of product.In the last few years, NOWSCO Well Service Ltd has developed a leak test process utilizing nitrogen mixed with helium as a tracer gas. With this innovative technology the industry is now able to eliminate the use of hydrocarbons during leak testing, and detect leakage rates as small as 0.1 cubic foot per year. This nitrogen/helium leak testing method was used on North Rankin 'A' platform.Some 559 leaks were found and rectified, of which 178 occurred in systems that had been previously leak tested with water. This highlights the inadequacy of water leak testing for gas handling systems.In May of 1984 an essentially leak-free start-up of the process equipment was accomplished on North Rankin 'A' Platform, which is attributed to the helium leak detection method used in the commissioning programme.
RIFT AND DRIFT IN THE DAMPIER SUB-BASIN, A SEISMIC AND STRUCTURAL INTERPRETATION
Authors: Veenstra E.
Published: August 2017

Quality improvements in marine reflection seismic data over recent years have lead to a better understanding of the relationships between seismo-stratigraphical sequences present in the Dampier Sub-basin and those in adjacent areas. The "drift-onset" unconformity, which separates the syntectonic rift sequence from the post-tectonic drift sequence, can now be seismically recognised as a single unfaulted surface. Previously this unconformity was interpreted to be faulted. In places this surface had some 2400 m of palaeotopography in the form of an escarpment. This escarpment was formed by tectonic movements and subsequent erosion some time in the Callovian, probably as a consequence of the opening of the Indian Ocean.The presence of Callovian and Upper Jurassic marine sands on the Rankin Platform shows that the Rankin Platform was in places submerged during Callovian and Upper Jurassic times. Furthermore, the Dampier Sub- basin must have been more than 2000 m deep immediately following the causal tectonic event. The escarpment was rapidly buried, with 1200 m of sediments locally deposited by the end of the Callovian and was finally buried by Neocomian times. Thereafter the Rankin Platform and Dampier Sub-basin have subsided.
SOURCE POTENTIAL OF UPPER TRIASSIC FLUVIO-DELTAIC SYSTEMS OF THE EXMOUTH PLATEAU
Authors: Cook A.C. , Smyth Michelle , Vos R.G.
Published: August 2017

The fluvio-deltaic rocks of the Upper Triassic Mungaroo Formation of the Exmouth Plateau contain abundant organic material in the form of both coal seams and dispersed fragments. Several thousand metres of these sediments lie within the oil generation window (0.5 to 1.3 per cent R̅O max vitrinite), but they have commonly not been considered as source rocks for oil because the organic matter is of terrestrial origin. Increasing acceptance of plant material as a source for oil warrants an assessment of the oil generating potential of the Mungaroo Formation.The maceral composition of organic matter is dependent on the depositional environment. The large-scale uniformity of environments (mostly lower delta plain) in the Mungaroo Formation leads to a similarity in the organic matter, with an approximate composition of 90 per cent vitrinite in the coals and 50 per cent vitrinite, 20 per cent exinite and 30 per cent inertinite for the dispersed organic matter (DOM). The exception to this is organic material from the alluvial plain environment, where the coal has a vitrinite content of 60 per cent and the dispersed organic matter has a composition of 20 per cent vitrinite, 20 per cent exinite and 60 per cent inertinite.A quantitative assessment of the oil-generating potential of the organic matter based on maceral composition, vitrinite reflectance and volume of coal and dispersed organic matter was made for a range of time-rock units. On this basis, the Carnian-Ladinian and Carnian sequences have the best source potentials.On the basis of vitrinite reflectance measurements, it appears that the Mungaroo Formation has been generating oil since late in the Triassic or early in the Jurassic, through to the Tertiary. Lack of suitable seals during the early generative phase may have permitted some oil to escape. However, significant oil generation has occurred subsequent to the deposition of the younger Mesozoic sequences, when trapping and sealing were more effective.
PRE-EOCENE STRATIGRAPHY, STRUCTURE, AND PETROLEUM POTENTIAL OF THE BASS BASIN
Authors: Williamson P.E. , Pigram C.J. , Colwell J.B. , Scherl A.S. , Lockwood K.L. , Branson J.C.
Published: August 2017

Exploration in the Bass Basin has mainly concentrated on the Eocene part of the Eastern View Coal Measures with the pre-Eocene stratigraphy hardly being tested. Structural mapping using a good quality Bureau of Mineral Resources regional seismic survey and infill industry seismic data, in conjunction with seismic stratigraphy and well data, has generated an understanding of the structure and stratigraphy of the pre- Eocene basin, which suggests that exploration potential exists in structural and stratigraphic leads of both Paleocene and Cretaceous age.The Paleocene structure is influenced by the reactivation of normal faults developed at the time of the mid Cretaceous rift unconformity and reflects drape over deeper features. Consequently fault dependent structural closures often persist from Paleocene to (?)Jurassic levels. Possible stratigraphic traps are also observed against horst blocks and around the basin margins. The longitudinal fault directions are northwest and west northwest with an oblique northerly direction and a prevailing north northeasterly transverse direction.The Paieocene and Upper Cretaceous part of the Eastern View Coal Measures consists of sands, shales and coals deposited in alluvial fans, on flood plains, and in lakes. These are underlain by Early Cretaceous Otway Groups, sands, shales and volcanics. Both intervals have potential reservoir and source rocks and often occur at mature depths. No pre-Otway Group sediments have been encountered in wells in the Bass Basin. However, the Permo- Carboniferous and possibly Triassic strata that occur in Northern Tasmania exhibit reservoir and source rock potential and may extend offshore beneath the Bass Basin.Pre-Eocene structural and stratigraphic studies of the Bass Basin thus point to reservoir and hydrocarbon source potential for possible multiple hydrocarbon exploration targets.
ECONOMICS OF CONTRACT DRILLING—A DILEMMA
Authors: Bushell J.E.
Published: August 2017

By comparison within the petroleum exploration industry, few other industries have been confronted with as many severe economic and political shocks resulting in loss of control over activities and assets through government scrutiny and imposed decisions. Throughout their thirty-year history, Australian companies involved in the contract drilling industry have been faced with cyclic supply and demand trends.In 1982, as a result of the downturn in exploration in Canada due to the policies of Pierre Trudeau, the Australian contract drilling industry was flooded by an oversupply of rigs resulting in a reduction in rates by up to 35 per cent. This oversupply situation continues today in Australia, and contractors are now facing severe economic difficulties as they attempt to gain a reasonable market share to ensure that their nucleus of highly trained personnel are not lost from the industry.Contractors have implemented cost control programs which if continued for some time will have adverse effects. As maintenance programs have been curtailed, capital expenditure has all but been eliminated and training programs deferred.Shareholders in drilling companies have become so disenchanted with their return on funds employed that they are looking to divest these assets. In this time of uncertainly one wonders where the industry, so vital for our national good, is going. The plight of the contractor is one area which must be addressed by the whole industry.
FOREIGN FUNDING OF THE AUSTRALIAN PETROLEUM INDUSTRY — IMPORTANT ASPECTS OF THE DIRECT INVESTMENT DECISION PROCESS
Authors: McKee J.
Published: August 2017

The paper provides an outline of the financial aspects of the foreign direct investment decision process and an understanding of how this can help attract funds for Australian petroleum exploration and development.Proposals to foreign investors are seen to require specific personal presentations. The investors' view of risk is discussed under the headings of political, economic, and environmental, and the major risk factors that require understanding are shown to be country risk; exchange rate risk—rate forecasting and exposure management; and international taxation.The techniques in assessing country risk are reviewed, and the methodology of international banks assessed. The Go/No-Go, Premium for Risk, Range of Estimates, and Risk Analysis techniques are described.In considering the forecasting of exchange rate movements it is recognized that, while there is no adequate forecasting measure, the major variables of comparative prices, interest rates, and comparative money supply require attention. The mechanistic tools of purchasing parity theory and the Fisher effect formula on interest are therefore outlined.The management strategy in the management of exchange rate movement exposure is seen to require a determination of economic exposure, the observance of basic rules in currency grouping, and market operation guidelines. A management guide is set down for reference.A reference to international taxation indicates the need of the tax planner to consider comparative taxation domicile of investment, and corporate structure.The basic taxation principles that apply are seen as the necessity to plan in after-tax terms; the importance of determining the nature and sources of taxes; and the requirement of a full knowledge of relevant double taxation agreements and local tax administration regulations.The role of the Australian petroleum industry in attracting foreign investment is seen as promoting the provision of data, increased opportunities to invest, risk reduction through tax effective opportunities, and assisting in proposal presentations.The need for earlier release of exploration data is expressed, as is the development of comprehensive updated data packages—which would include basin reviews—for use by industry. A zoning approach to areal permit size that provides for a reduction in permit size with exploration maturity is seen as an approach to increasing investment opportunities. Finally, APEA is encouraged to take a leading role in encouraging foreign investment through direct participation in presentations.
NATURAL GAS—THE NEED TO UNDERSTAND THE MARKET
Authors: Maxwell D.P.
Published: August 2017

Australia is a nation rich in natural gas resources.Natural gas markets, historically, have been developed following a major discovery nearby. Natural gas is now firmly entrenched as a major primary fuel in a competitive and dynamic market.Marketing theory indicates that sales of a product can be broken into three phases: introduction-growth, maturity, and decline.The Australian natural gas markets are presently entering the mature phase. To sustain the economic incentive for further exploration, natural gas explorers and producers need to become more aware of the market environment in which they compete. Development of new markets and technology today will ensure the need for gas exploration in the future.
GEOLOGICAL REASONING FOR THE PETROLEUM SOURCE ROCKS OF KNOWN FIELDS
Authors: Chapman R.E.
Published: August 2017

Geological reasoning for the petroleum source-migration-accumulation relationships centres around petroleum composition and its variability, water composition and its variability, and stratigraphy. For example, a field with several pools of petroleum of different compositions is likely to have been sourced from several distinct source rocks that are stratigraphically associated with the reservoir rocks. If water compositions are also variable, the conclusion is reinforced. A field with several pools of petroleum of similar quality was sourced either from similar source rocks that are stratigraphically associated with the reservoirs, or from a single source that is removed from the accumulations. There are also considerations of wax content, environment of deposition of the reservoir sequence, sand/shale ratios, and faulting.Geological reasoning does not always lead to the same conclusions as geochemical reasoning. Such cases are particularly important for petroleum geology because they should lead us to a better understanding of the source-migration-accumulation relationships. Some of the remaining giant oil accumulations of the world may be in areas that would be discarded on geochemical evidence. Most of the crude oil remaining to be discovered will be in relatively few giant fields, so misunderstanding could jeopardize our future supplies.
COMPARISON OF SELECTED NON-MARINE PETROLEUM-BEARING BASINS IN AUSTRALIA AND CHINA
Authors: Mai P.S. Moore D.K. Hobday H. , Sun Z.C.
Published: August 2017

This paper summarises the geology and hydrocarbon potential of two Chinese and two Australian basins (Ordos, Northern Jiangsu, Eromanga, and Surat basins) in order to compare factors affecting the generation, migration, and entrapment of hydrocarbons. In all four basins, hydrocarbons are generated from nonmarine source rocks of lacustrine and fluvial-overbank origin. While the Chinese and Australian basins contain a similar range of sedimentary facies, from alluvial fan to lacustrine, the arrangement and relative thicknesses of these facies vary considerably as a result of different tectonic and palaeoclimatic settings.During the Triassic, the Ordos Basin was dominated by retroarc foredeep subsidence and the development of deep, fresh-water lakes with anoxic bottom waters. This non-bioturbated substrate, with Type I and II kerogen precursors, provided an excellent oil source for adjacent fan-delta, deltaic, and fluvial reservoirs, and for the unconformably overlying Jurassic fluvial valley-fill sandstone reservoirs.The Northern Jiangsu Basin was initiated by back-arc extension and underwent very rapid half-graben subsidence in the Eocene. Alluvial fan, shoreline, and fluvial facies aggraded in a relatively narrow zone along the active, faulted margin, and merged laterally into organic-rich shales which provided a local source for oil.By comparison, the Eromanga/Surat basins developed in response to gentle downwarp and reactivation of older structural trends. Reservoirs are largely restricted to craton-derived quartzose facies such as in the Hutton, Precipice, and Namur sandstones. There is probably a dual source for oil, from the underlying Permian (which may be the dominant source in the Surat Basin), and from shales deposited in shallow, partly oxygenated lakes and overbank facies of Jurassic age (important in the Eromanga, and possibly subordinate in the Surat Basin). Deep lacustrine facies, typical of the Chinese basins, did not develop. The greater abundance of oil in the Chinese nonmarine basins is explained in terms of tectonic and palaeoclimatic factors which yielded thicker and better quality source rocks, more rapid maturation, and a better juxtaposition of source rocks and good-quality reservoirs, thus providing short, highly efficient migration routes.
THE YELLOW DRUM FORMATION—A HYDROCARBON RESERVOIR, CANNING BASIN, WESTERN AUSTRALIA
Authors: Moors H.T.
Published: August 2017

The Yellow Drum Formation has an extensive distribution on the Lennard Shelf of the Canning Basin. It straddles the Devonian-Carboniferous boundary and is a peritidal clearwater deposit. The environment of deposition controlled the diagenetic path followed by the sediments. The bulk of the formation was penecontem-poraneously dolomitized to a fine-grained crystalline rock with moderate porosity, with permeability too low to be an effective oil reservoir. However, in some facies the dolomite was coarser grained producing a good reservoir. Tertiary porosity was created by later leaching of remnant calcite, turning a good reservoir into an excellent reservoir.The environment of deposition is readily identified from examination of the sediments, which can then be located in a depositional model. From this the reservoir potential can be predicted. Conversely, from the identification of the portion of the depositional model in which the sediments were deposited it is possible to predict in what direction better reservoir development exists.
A REVIEW OF GEOPHYSICAL EXPLORATION IN THE POLDA BASIN, SOUTH AUSTRALIA
Authors: Nelson R.G. , Crabb T.N. , Gerdes R.A.
Published: August 2017

The Polda Basin is an intracratonic basin, at least 5000 m in depth, extending from the edge of the Great Australian Bight nearly 400 km east to the centre of Eyre Peninsula in southern South Australia, it can now be recognised as a structural feature of some antiquity, originating possibly as a crustal downwarp in Proterozoic time during the same orogenic regime that gave rise to the Officer and Amadeus basins of central Australia, with which it has strong affinities. Its internal structure indicates that it has been subject to the same orogenic episodes that have affected southern and central Australia, culminating in rotational block faulting associated with the final pull-apart of Gondwanaland. Extensive salt mobilisation observed on seismic sections, confirmed by the drilling of the Mercury 1 and Columbia 1 wells, supports the concept of the basin's Cambrian or Precam-brian origins.The exploration history of the basin is a useful example of the application of a number of geophysical disciplines to arrive at a satisfactory interpretation. A reappraisal of geophysical data was undertaken after Outback Oil N.L. drillhole Gemini 1 penetrated 'uneconomic' basement at 856 m, far short of the anticipated sedimentary section of 1830-2440 m. Interpretation of shipborne magnetic data, not previously considered, indicated that a seismic horizon close to where Gemini 1 penetrated igneous rock was related to a thin layer of magnetic material which did not correspond to deep magnetic basement. Further detailed aeromagnetic and seismic studies confirmed this interpretation, which was tested by the drilling of two exploration wells. Mercury 1 and Columbia 1. Although unsuccessful as hydrocarbon discovery wells, these two wells confirmed the overall validity of the interpretation. Stratigraphic information derived from these wells and from further geophysical studies and drilling onshore have led to a new assessment of the basin and its potential.
RESERVOIR GEOLOGICAL MODELLING OF THE NORTH RANKIN FIELD, NORTHWEST AUSTRALIA
Authors: Beston N.B.
Published: August 2017

The North Rankin Field off northwestern Australia provides the major part of the gas reserves for the North West Shelf Project, one of the largest and most ambitious natural resource developments yet undertaken in Australia. Detailed reservoir geological modelling coupled with a three dimensional reservoir simulator have strongly enhanced development planning of the field.The North Rankin structure is a large horst feature of Upper Triassic to Lower Jurassic fluvial and marginal marine sediments unconformably overlain by Cretaceous claystones and marls. The sequence is comprised of braided stream 'sheet like' sandstones, fluvial meandering stream and floodplain sediments, and mixed marginal marine and fluvial channel sandstones.Comprehensive reservoir geological studies involving the examination of reservoir quality, distribution, and continuity were undertaken and combined with an extensive three dimensional seismic survey to provide improved structural definition. The resultant reservoir geological model, which required close interaction and integration of all petroleum engineering disciplines, provided not only the geological basis for improving the estimate of field reserves but also formed the geological input for a reservoir simulation model to optimise the development planning of the North Rankin Field and to predict the reservoir performance of this internally faulted field.The completion of the Domestic Gas Phase of the Project, which involved the drilling of seven development wells, has confirmed the reservoir geological/structural model thus providing a firm basis for the future development planning of the gas recycling and liquefied natural gas phases of the North West Shelf Project.
COMMERCIAL ASPECTS OF UNDERGROUND GAS STORAGE IN AUSTRALIA
Authors: Willcocks R.M.
Published: August 2017

Underground gas storage is becoming increasingly important in Australia with the discovery of significant gas reserves, mostly in places distant from the expanding markets for gas.Gas has been stored in the offshore Barracouta Field since 1971 and storage projects are either being considered or underway in New South Wales, South Australia, Western Australia and the Northern Territory.Although not a great deal of attention has been paid to the legal, tax and administrative aspects of underground gas storage, the position is likely to change the more it becomes apparent that such storage is commercially and technically viable.The applicable legal regime will depend on the location of the storage. Offshore gas storage on the continental shelf beyond the coastal waters of a state is subject to Commonwealth jurisdiction. In state coastal waters, it is subject to state laws. Onshore, it is subject to the jurisdiction of the state or territory in which the storage occurs.Offshore beyond state coastal waters the Australian government has sovereign rights over the continental shelf for the purposes of exploring the continental shelf and exploiting its natural resources.There are a number of legal uncertainties which arise from gas storage which will be of concern to financiers as well as gas storers. With certain exceptions, there is doubt as to ownership of stored gas, and the right to inject and store gas. The right of withdrawal however would appear to fall under the right which normally exists under a production lease to 'mine' petroleum, or to conduct 'petroleum mining operations'. Except in Victoria, and to a significantly lesser extent South Australia, there is very little legislative guidance on the topic and related issues.The question whether stored gas is trading stock is the subject of Income Tax Ruling 2190 of 10 September 1985. This puts at rest, in practical terms, in any event, some of the doubts which existed as to the characterisation for income tax purposes of gas stored near the place of original extraction — the ruling concluded that 'reinjected processed gas should not be treated as trading stock for income tax purposes'.It is concluded that there is a good case for those Australian jurisdictions in which gas storage is occurring, or is about to occur, to provide legislation to eliminate the uncertainties.
GIPPSLAND TERRESTRIAL OILS — RECOGNITION OF COMPOSITIONAL VARIATIONS DUE TO MATURITY AND BIODEGRADATION EFFECTS
Authors: Burns B.J. , Bostwick T.R. , Emmett J.K.
Published: August 2017

The Gippsland oils, though derived from a common terrestrial source, show considerable variation in their chemical compositions. They range from being very waxy and paraffinic to light, almost condensate-like, oils. Much of this variation can be explained as a function of increasing maturity at the time of generation, with the earliest generated oil being characterised by dominant n-alkanes in the C22-23 is range, remnant odd-over-even preference above C25 and general lack of lower molecular weight gasoline and kerosene range hydrocarbons. At peak generation, the oils show a trimodal distribution as increased thermal cracking generates lighter hydrocarbons with a maximum around n-C7-8 and lesser maxima at n-C14 and n-C23. The most mature oils show the destruction of nearly all of the high molecular weight hydrocarbons and exhibit a unimodal composition maximising at n-C9 or less. These light oils are nearly always associated with gas caps, suggesting a link between the two. Secondary alteration by biodegradation and water-washing is common but its severity and the composition of the resulting oil is varied. Reservoir temperature is one of the key controls on biodegradation with no degraded oils observed at temperatures above 75-80°C. This, combined with the known limits of fresh water influx, makes it possible to predict the probable biodegradation effects on reservoired oil prior to drilling.
RECENT ORGANIC GEOCHEMICAL EVALUATION OF THE CENTRAL EROMANGA BASIN
Authors: Khorasani Ganjavar Khavari
Published: August 2017

Systematic analyses of bulk properties and of molecular composition, by gas chromatography (GC), fluorescence spectroscopy, gas chromatography-mass spectroscopy (GC-MS), reflectance photometry and 'Rock-Eval' pyrolysis of core samples from three stratigraphic bores from the central and northern-central Eromanga Basin, reveal the following:The organic facies variations in the central Eromanga are considerable; however, the biofacies can be grouped into three major types.The sediments do not enter the mature zone of oil generation until a reflectance level of 0.65 per cent Rv max. or higher is reached. The Birkhead Formation, with a 'hydrogen-rich' type III kerogen, is only marginally mature and the amounts of hydrocarbons already generated are minor. In the Early Jurassic sedimentary unit (Basal Jurassic Shale Unit), however, there is a distinct increase in the level of S1/Organic Carbon indices and in the maturity of organic matter. While the extracts from younger Jurassic sequences of the basin display a substantial waxy character, the bitumens derived from the Basal Jurassic Unit are highly aromatic in character and contain few saturated hydrocarbons.
STRUCTURING AND CONTROLS ON DEVONIAN REEF DEVELOPMENT ON THE NORTH-WEST BARBWIRE AND ADJACENT TERRACES, CANNING BASIN
Authors: Begg John
Published: August 2017

The major terraces flanking the southern margin of the Fitzroy Trough have had a complex history of development involving at least four major episodes of structuring with varying degrees of intensity from the Mid-Late Ordovician Rodingan Movement through to the Latest Triassic-Early Jurassic Fitzroy Movement. Extensive salt tectonism associated with the massive evaporite deposits of the Silurian Carribuddy Formation has also had a profound effect on structuring in these areas.Despite sparse well control, seismic recognition of the resultant structural styles has provided the basis for more comprehensive modelling of the main controls on sedimentation than has previously been possible.In particular, a complex sub-surface distribution of stacked Devonian carbonate platform and reef complexes can now be recognised, having similar morphologies to the spectacular outcrop on the northern side of the Fitzroy Trough. In addition to broad platform areas, individual peninsula developments, isolated atolls and extensive inter-reef seaways were present at both Pillara and Nullara cycle levels, largely controlled by faulting initiated in the Mid-Devonian and influenced in some cases by salt diapirism.Identification of the carbonate and associated palaeogeographic trends will provide direction for future exploration efforts in this wildcat area.
THE HUTTON SANDSTONE-BIRKHEAD FORMATION TRANSITION, ATP 269P(1), EROMANGA BASIN
Authors: Watts K.J.
Published: August 2017

The Hutton Sandstone and Birkhead Formation are the reservoir and seal, respectively, for most ofthe oil discovered in the Eromanga Basin. The traps are generally simple anticlinal closures; however stratigraphic complexities are common. Development well failures in ATP 269P(1) are commonly caused by stratigraphic variations at the Hutton-Birkhead transition.In ATP 269P(1) two distinct sandstone compositions are present over the Hutton-Birkhead transition, and are end-members of a spectrum of compositions. The first end-member consists of porous and permeable quartzose sandstone which is typical of the Hutton Sandstone. The second end-member is a lithic labile sandstone which is generally not of reservoir quality and is typical of the Birkhead Formation. Mixed and interbedded varieties are common, and are included in the Birkhead. The sandstone composition indicates that the quartzose 'Hutton' variety was derived from a stable, plutonic-metamorphic craton, whereas the lithic 'Birkhead' variety was sourced from a tectonically mobile belt, consisting of acid to intermediate volcanics, regional metamorphics, and metasediments.The Bodalla South Field displays a gradational change from quartzose sandstone in the Hutton to mixed and interbedded varieties in the Birkhead. Substantial range in reservoir quality is seen in the field and is related to sandstone composition and to a fluviodeltaic environment of deposition. In the Kenmore Field lithic sandstone, deposited in channels eroded into the quartzose sediments, provides stratigraphic enhancement of the structural closure.Similar relationships are seen in the Jackson-Naccowlah area and the Surat Basin and are linked to a change from a single provenance during deposition of the Hutton to a dual provenance during deposition of the Birkhead. This change was caused by increased activity in a mid-Jurassic arc system off the present Queensland coast and has important implications for petroleum exploration in the Eromanga and Surat Basins.
FAULT PLANE RESOLUTION USING THE LOW-FOLD 3D SEISMIC TECHNIQUE OVER WOODADA GAS FIELD, PERTH BASIN, WESTERN AUSTRALIA
Authors: Evans B.J. , Paterson G.A. , Frey S.E.
Published: August 2017

During August 1984, a conventional 2D seismic line and a single fold 3D seismic survey were recorded over the Woodada Gas Field, North Perth Basin, Western Australia. This survey was a joint venture between the Allied Geophysical Laboratories at the University of Houston and the Exploration Seismology Centre's Field Research Laboratory at the Western Australian Institute of Technology. Previous seismic data were so poor that there was confusion about fault orientation and structure in the survey area. In addition, the fault strike direction and extent were unknown at this location. Consequently, 3D seismic acquisition and processing techniques appeared highly applicable to this geological problem.In general, progressive development of seismic data acquisition methods has been towards higher channel, higher multifold 2D and 3D surveys. However, at the Allied Geophysical Laboratories, processing techniques for single-fold 3D data have been developed using model tank data. This processing technique — LO-FOLD 3D — was used to field trial the method, and to test its ability to define faulting between the gas producing well Indoon 1 and dry step-out well Woodada 9. Previous usage of the single-fold 3D survey method was to delineate reefal structures in the Michigan Basin. Beyond this, no published articles discuss the method.With single-fold data, velocity analysis and coherent noise are a problem. Consequently, 2D bin lines through the 3D volume of data were processed in order to improve the signal to noise ratios. The objective was to delineate the fault orientation in the Carynginia Formation, located between 1.3 and 1.5 seconds. Fault delineation was determined from 2D bin lines and time slices, and is interpreted to run diagonally between the two wells.