bluuebunny/crossref_metadata_2025 huggingface dataset:
REVIEW OF THE PALAEOZOIC STRATIGRAPHY AND PETROLEUM POTENTIAL OF NORTHERN SOUTH AUSTRALIA
Authors: Devine S. B. , Youngs B. C.
Published: August 2017

The Amadeus, Warburton, Officer, Adavale, Arckaringa, Pedirka, Cooper and Great Artesian Basins form a complex system of overlapping basins in central Australia. Cambrian rocks are widespread in the Amadeus, Warburton and possibly the Officer Basins and are marked by the major role of carbonate deposition. Gas and oil shows are known from the Amadeus and Warburton Basins. In South Australia their reservoir potential lies in shoreline clean-up of generally dirty marine sandstones and porosity-permeability associated with archaeocyathid bioherms or dolomitization of limestones.The Ordovician rocks follow the widespread distribution of the Cambrian rocks and are distinctive for thick quartzites and graptolitic shales. In South Australia, the Warburton and Officer Basins may have facies developed which are similar to the Pacoota and Stairway Sandstones, the reservoir rocks for the Amadeus Basin gas and oil fields. Large anticlinal structures have recently been suggested by S.A. Mines Department geophysical work in the Officer Basin which enhances the potential.Red beds are distinctive in the Devonian System. Deposition apparently spilt into the peri-Musgrave Block area and the Adavale Basin to Innamincka area. A thickness of over 3 000 metres of Devonian rocks was drilled in the Officer Basin which contained some reservoir rock lithology. The petroleum potential in South Australia is relatively unattractive.Some 3.4 trillion cu ft of deliverable gas reserves have been established already in the Permian sediments of the Cooper Basin which are up to 900 m thick. The Early Permian sediments of the Pedirka Basin which may be at least 500 m thick may hold similar petroleum potential.
DEVELOPMENT OF THE TERTIARY OFFSHORE PAPUAN BASIN
Authors: Tallis N. C.
Published: August 2017

Marine seismic studies combined with wildcat drilling in the Gulf of Papua have provided a comprehensive insight into the geology of the offshore Papuan Basin. The Basin adjoins a downwarped but structurally rigid segment of the Australian continental shield in the west, and the Coral Sea Basin in the southeast. It incorporates arcuate geosynclinal development eastward and northward beyond the continental margin. The pre-Tertiary history is relatively obscure. Jurassic-Lower Cretaceous clastic sediments overlie granites and volcanics of the continental shield in the west. Eastward, the record is masked by great thicknesses of Tertiary strata, and the pre-Tertiary may be represented in outcrop by a metamorphic series of indeterminate age.The Tertiary offshore basin developed in three distinct phases, commencing in Late Cretaceous/Early Eocene time, when seas transgressed from east to west across a peneplaned surface. An eastward-thickening wedge of argillaceous limestones and cherts was deposited. Regression and erosion occurred in Late Eocene/Early Oligocene time, possibly in association with upwarp of the oceanic crust, which created an eastern volcanic borderland. Typical orthogeosynclinal sedimentation followed in Early Miocene time, with reef, shoal and pelagic limestones deposited marginal to the stable western (continental) shelf, and with prolific volcanism associated with the eastern (oceanic) flank. This volcanism was the source for a thick pile of mudstone-greywacke sediments which was deposited in an intermediate eugeosyncline.This second phase was modified in Late Miocene time by regional uplift, and by development of the Central Mountain geanticlinal belt. This created an immense southeasterly pro-grading system which rapidly buried the Early Miocene profile. These fine grained clastic Plio-Pleistocene sediments have been highly deformed by gravitational and diapiric influences in the east-central portion of the basin. Huge volumes of sediment are still being transported southeastward into the Coral Sea Basin.
GEOLOGY AND PETROLEUM PROSPECTS OF SERAM ISLAND, EASTERN INDONESIA
Authors: Zillman N. J. , Paten R. J.
Published: August 2017

The Island of Seram is located near the eastern end of the Indonesian Archipelago about 250 km southwest of Irian Jaya and 1000 km north of Darwin.The two main Late Tertiary to Quaternary basins (the Bula and Wahai Basins) totalling approximately 6000 km2 occur both offshore and onshore along the northern and northeastern coasts of the island. Several smaller basins of similar age occur along the eastern, southern and northwestern coasts.Sedimentation in the Bula and Wahai Basins began in the Early Pliocene with a marine transgression which continued into the Early Pleistocene and resulted in the deposition of bathyal facies mudstone and siltstone in the deeper parts of the basins. In the Early Pleistocene uplift occurred resulting in the formation of a regional unconformity in the sedimcn tary sequence. This uplift was followed by further transgression and deposition of neritic sediments during later Pleistocene to Recent times. The estimated maximum thickness of sediments in the Bula and Wahai Basins is 1400 and 2800 m respectively.Although the basement rocks of Seram have been severely folded and faulted, structural deformation within the Plio-Pleistocene basins has been much more subdued, resulting in minor tilting, draping of sediments over basement highs or Pleistocene reefs, and more rarely, small, down-to-the-basin faults near the basin margins.The Bula Basin is a proven petroliferous basin with the small stratigraphie Bula-Lemun Oilfield of Pleistocene age on its northwestern margin. In addition there are abundant surface oil seeps and good free oil shows have been recorded from wells drilled in the Belien-Kola area. Porous beach and bar sands and reefal limestones have been encountered within the onlapping Pleistocene sediments. Future exploration in Seram has good prospects of discovering further oilfields of the Bula-Lemun type.
DOLOMITIZED SANDSTONES: A MARLIN FIELD GAS-RESERVES ASSESSMENT PROBLEM
Authors: Svalbe A. K.
Published: August 2017

Dolomite cement had been recognised within fluvio-deltaic facies sandstones of the Gippsland Basin Marlin field N-1 (Eocene) gas reservoir in the initial wildcat and two stepout wells. Although initially thought to be insignificant, the additional control provided by development drilling indicated that the degree and extent of dolomite cementation within the reservoir sandstones could be wide-ranging enough significantly to reduce reserves and influence reservoir performance. A study to define the area and degree of dolomite cementation within the reservoir showed that the distribution pattern within the 5 major sandstone units fell into 3 distinct groups. Whereas the 3 stratigraphically oldest (N-1.5, N-1.4 and N-1.3) units were only dolomitized within the northeastern portion of the field area, the N-1.2 unit was dolomite cemented field-wide. The youngest (N-1.1) unit, which unconformably overlies the truncated N-1.2 unit, is devoid of significant dolomite influence.Dolomitization of the N-1 sandstone units is interpreted to have occurred during a phase of estuarine-restricted marine shale deposition which followed the truncation of the N-1.2 sandstone unit. Although these estuarine dolomitic shales are absent by erosion at Marlin, they are present in the adjacent Tuna field area. Distribution of the dolomite cement within the reservoir sandstones was controlled by the subcrop pattern of the sandstone units during the deposition of the estuarine sediments.Petrological and x-ray diffraction information strongly suggest primary dolomite cementation, and not dolomitization of some pre-existing carbonate cement. The petrological, core analysis and geological information was integrated with the interpretation of wireline porosity logs to obtain reservoir unit average porosities and calculate reserves.The currently estimated initial N-1 reservoir dry gas reserves are 2.72 TSCF. If the reservoir sandstones were not dolomite cemented, reserves would be 3.15 TSCF, that is 14% greater.
WIRELINE FORMATION-TESTER PERFORMANCE ON THE NORTH WEST SHELF
Authors: Agostini M. D.
Published: August 2017

The formation-interval-tester was introduced to the North West Shelf in December, 1970 Originally it was used as a first-look test method, with drill stem testing retained as the standard evaluation technique in all potential reservoir sections. Systematic use of this technique in parallel with drill-stem testing has allowed the accumulation of a significant volume of comparative data. This has provided a unique opportunity to examine the validity of wireline-testing as an alternative to the more traditional method of reservoir evaluation.The wireline-tester has been found to be a reliable indicator of movable hydrocarbons in reservoir rock, after experience allowed the development of regional interpretation limits. Such variables as gas:oil ratios and oil gravities are determined within acceptable limits of accuracy. Formation pressure determinations are consistent' and are thought to be more reliable than those derived from drill-stem-testing. With the data available it is normally possible to calculate the indicated formation permeability. This however being a single point determination the result is of questionable value. Experience has shown that "order of magnitude" agreement is normally achieved between wireline-tester permeabilities and those determined from drill-stem-testing in the same interval.The reduction in cost resulting from the application of this technique is particularly significant. Savings may be related directly to the relative reduction in rig time required by this operation compared with that required for drill-stem-testing. As the cost of offshore operations increases rapidly the resultant savings will grow in significance.Also of concern in all well-testing operations is the risk to which the rig and personnel are subjected. On floating offshore rigs the flowing well condition required by drill-stem-testing requires the acceptance of certain associated risks. Wireline testing is by comparison a risk-free operation.The recognition of the inherent limits of this approach to well testing is important if satisfactory results are to be achieved. Where the required reservoir parameters are those that can be satisfactorily determined with the wireline tester it offers a real alternative to the more traditional evaluation techniques.
AN ASSESSMENT OF THE ONSHORE PETROLEUM POTENTIAL OF CENTRAL AND SOUTH AUSTRALIA
Authors: Devine S. Bevan
Published: August 2017

THE AMADEUS. Arrowie, Officer and Warburton Basins contain pre-Permian sediments with petroleum potential. The Cooper and Pedirka Basins have petroleum potential in Permian sediments. The Murray Basin contains Devonian. Permian and Cretaceous sediments with some potential.The Cooper Basin has established reserves of 6.5 t.c.f. raw gas in place in 16 fields from which Adelaide and Sydney markets will be served. Another seven small or unassessed fields have been discovered. Further exploration should probably double the established reserves. Wildcat drilling success is 1 in 3 so far.The Pedirka Basin is in an early stage of exploration. The geological elements of good sandstone reservoir beds, coaiy source beds, fold and fault structures and geological history analogous to the Cooper Basin gives it great attraction to the explorationist.The Amadeus Basin is an established petroleum province with gas and gas/oil deposits established in the enormous fold structures of the Palm Valley and Mereenie Fields respectively. Further prospects remain to be drilled but prior to drilling a market must be established for these resources which are in the centre of the Continent.Many geological and geophysical features of the Officer Basin are analogous to the Amadeus Basin but it is virtually unexplored. The basin is a high cost, high risk, possible high reward exploration area.
THE GEOLOGICAL EVOLUTION OF THE CONTINENTAL MARGIN OFF NORTHWEST AUSTRALIA
Authors: Powell D.E.
Published: August 2017

The area comprising the Northwest Shelf of Australia is a good example of an 'Atlantic-type' continental margin. It is characterised by a series of major sedimentary basins of Mesozoic age, which generally parallel the present coastline. In each of these depocentres distinct lithotectonic units can be recognised which are related to phases of rifting and subsequent continental breakup. The pre-breakup rift valley and intracratonic basin stages are represented by a very thick Permian to Middle Jurassic series of mainly fluviodeltaic sediments. Breakup took place near the end of the Middle Jurassic and was accompanied by large-scale block faulting with associated uplift and erosion. As a result the ensuing Upper Jurassic to Lower Cretaceous marine transgression took place over a highly irregular palaeotopographic surface. With continuing post-breakup subsidence, open marine conditions became widespread by Upper Cretaceous time. Since the mid-Eocene the deposition of a thick prograding wedge of mainly carbonate sediments has given a general northwesterly regional tilt to the shelf. Such progradation is characteristic of a fully-evolved Atlantic-type continental margin.Hydrocarbon occurrences on the Northwest Shelf can be related to the tectonic evolution. Major gas/condensate discoveries have been encountered in fluviodeltaic reservoirs within the block-faulted pre-breakup sequence, sealed by post-breakup transgressive marine shales which also provide important source intervals. In addition, some sandstone units of the transgressive series are hydrocarbon-bearing. The prolonged post-breakup subsidence and accompanying thick sedimentation has ensured that source intervals have locally attained the necessary depth of burial for hydrocarbon generation.
TROBRIAND BASIN EXPLORATION, PAPUA NEW GUINEA
Authors: Tjhin K.T.
Published: August 2017

Regional studies suggested that the Solomon Sea would be underlain by upper Tertiary sediments inluding possible Miocene reef carbonates similar to those found in the Gulf of Papua and Irian Jaya. As the Trobriand area of the Solomon Sea lies in a zone of interaction between the Australian and Pacific tectonic plates, it was considered likely that Tertiary basins prospective for petroleum would be present. In 1969 the East Papua aeromagnetic survey revealed a magnetic low which was interpreted as a basin, here named the Trobriand Basin. A sedimentary section of some 3000 m, situated under shallow water was indicated.Amoco, Australian Oil & Gas and Southern Pacific Petroleum made application for and were granted exploration permit PNG/15P in June, 1971. The Group initially undertook field geological, aerial photographic and hydrographic surveys which revealed the presence of numerous Pliocene to Recent coral reefs throughout the permit and also indicated the likely nature of economic basement. Between April 1972 and May 1973, three marine seismic surveys by Western Geophysical produced 2250 km of reflection profiles. The seismic data suggest that the Trobriand Basin is an east-west trending graben filled with up to 5000 m of probable Miocene and younger sediments. Positive structures, of which several were interpreted as mid-Miocene reefs, were mapped.Two subsidised exploratory wells, Goodenough No. 1 and Nubiam No. 1, were drilled in 1973. Only minor and questionable hydrocarbon shows were encountered and both wells bottomed in Miocene volcaniclastics. The wells penetrated immature upper Tertiary sediments with low present and palaeo-geothermal gradients and consequently the sediments might be considered an unfavourable environment for petroleum generation. Nevertheless, the Trobriand Basin has not been adequately explored for hydrocarbon accumulations as only a portion of the Tertiary section has been evaluated in two widely-spaced wells.
A NEW LOOK AT THE OTWAY BASIN
Authors: Denham J. I. , Brown B. R.
Published: August 2017

The Otway Basin in western Victoria and eastern South Australia is a primarily offshore, Upper Cretaceous to Recent basin overlying a Lower Cretaceous basin. The major stratigraphic break developed after the deposition of the Upper Cretaceous Sherbrook Group. The offshore part of the basin in Victorian and Tasmanian waters has been explored since 1960 with a series of seismic surveys which improved in quality after 1971. Further offshore seismic data has been provided by the Bureau of Mineral Resources (BMR) Continental Margins Survey and by Shell Petrel lines. Seven wells have been drilled in Victorian/Tasmanian waters and six in South Australian waters.Stricter control of recording noise levels and continuous velocity analyses in processing, plus the use of refraction in seismic surveys since 1971 has enabled an improved interpretation of the Victorian/Tasmanian part of the basin.The Upper Cretaceous clastic sediments were deposited in an intracratonic basin with a maximum thickness of approximately 20 000 feet. The northeast flank is formed by a series of down-to-basin faults and increased movement on these faults and overall tilting gave a marginal basin in Tertiary time so that the section comprises a series of outbuilding sedimentary wedges.A major basin started to form across southern Australia in Lower Cretaceous times. In the Upper Cretaceous the three discrete Bass Strait basins developed from the major basin with Australia and Antarctica still in close relationship. Plate separation was associated with the change from an intracratonic basin to a marginal basin. Further separation produced no major change in the nature of deposition in the marginal basin.
INFLUENCE OF TIDAL PHENOMENA ON INTERPRETATION OF PRESSURE BUIILD-UP AND PULSE TESTS
Authors: Khurana A.K.
Published: August 2017

Bottom-hole pressure tests conducted in the Kingfish oil reservoir (located in Gippsland Basin - Offshore Victoria) during 1974 and 1975 using a high sensitivity surface recording electronic bottom-hole pressure gauge indicated the presence of sinusoidal pressure oscillations in the reservor. The oscillations are of the order of 0.1 psi in amplitude and their frequency suggests that they are in some way related to tidal phenomena.Although the oscillations do not affect production, they do influence interpretation of pressure build-up and pulse tests. Interpretations of both late time pressure build-up behaviour and pulse tests of small response magnitude and long time lags are considered to be particularly susceptible to errors due to these oscillations if they are not recognized and corrected for. Interpretations of early time pressure build-up data and pulse tests of definite response and relatively short time lags are not regarded as being significantly affected.The physical mechanism causing these pressure oscillations in the reservoirs is not known. However, one of the various possible hypotheses is that the Latrobe Formation sands could be outcropping on the ocean floor at abyssal depths southeast of Kingfish and that the pressure transients generated by changes in the hydrostatic head due to surfate tides are transmitted hydraulically to the reservoir. If this hypothesis is proved to be valid it could influence pressure performance predictions of Gippsland Basin reservoirs.
GEOCHEMISTRY AND SIGNIFICANCE OF COASTAL BITUMEN FROM SOUTHERN AND NORTHERN AUSTRALIA
Authors: McKirdy D M. , Horvath Z.
Published: August 2017

Detailed geochemical analysis of eleven Australian coastal bitumens - eight from ocean beaches in South Australia and western Victoria, and three from stranding sites on Bathurst Island and Cobourg Peninsula in the Northern Territory - shows that they are inspissated waxy crudes of low API gravity and low sulphur content.Only one bitumen appears not to be a natural crude, its composition is that of a weathered fuel oil. The rest may be divided into two types, as follows:Bitumens from Ocean Beach, Geltwood Beach and Sleaford Bay in South Australia are paraffinic to naphthenic in composition. Those from the Northern Territory, Victoria and Cape Northumberland, SA, together with a second sample from Geltwood Beach, are highly paraffinic to paraffinic. Both types of bitumen strand at Geltwood Beach where each contains appreciably more nickel (85-105 ppm) than bitumens of either type found elsewhere (3-30 ppm).The effects of exposure are more evident in some bitumens than in others. Weathering has involved evaporative loss of volatile components, bacterial degradation of n-alkanes up to C25, and an increase in asphaltenes at the expense of saturated hydrocarbons.A high proportion of long-chain (C23+) n-alkanes in the stranded crudes indicates that they are products of the diagenesis of mostly continental vegetation. However, their low pristane/phytane ratios (The geochemistry of the bitumens supports the belief that they represent natural submarine seepages. The amount of weathering sustained by the bitumens in each suite correlates with their exposure time. Their degree of alteration, in conjunction with a knowledge of local surface currents, can be used to establish their provenance. Cretaceous freshwater and paralic sediments are present at depth offshore in both the western Otway Basin and the Money Shoal Basin. These sediments constitute the most likely ultimate source for the immature oils that gave rise to the coastal bitumens now found scattered along the southern and northern coastlines of Australia.
THE STRUCTURE AND CARNARVON TERRACE STRATIGRAPHY OF THE AND WALLABY PLATEAU
Authors: Symonds P. A. , Cameron P. J.
Published: August 2017

The Carnarvon Terrace, Wallaby Plateau and adjacent slopes cover about 350 000 km2 beyond the continental shelf of central Western Australia. Water depths within the region range from about 600 m on the Carnarvon Terrace to 5000 m over the Cuvier Abyssal Plain.The dominant structural grain of the Carnarvon Terrace varies from north-northeast in the north to north-northwest in the south. A Palaeozoic structural high (Gascoyne Sub-basin) extends across the central Carnarvon Terrace. This feature is controlled by a Precambrian basement high. which is onlapped by sedimentary rocks of Ordovician to Carboniferous age. The high is bounded in the north by a major northeast trending fault, which may be an extension of the Rough Range Fault. Troughs trending parallel to the fault are part of the southern Exmouth Sub-basin; the largest trough contains up to 2000 m of possible Triassic and Jurassic sediments. A north-northwest trending half-graben 600 km long and up to 100 km wide, bounds the Palaeozoic high to the south. Normal faults, downthrown to the west, are common within this half-graben, which appears to connect with the Abrolhos Sub-basin and thus probably contains Permian, Triassic and Jurassic section.Northwest and possibly north-northeast trends occur on the Wallaby Plateau. Much of the Plateau consists of folded (?)Palaeozoic rocks and possibly shallow Proterozoic basement, with igneous bodies abundant on its western and southern margins.Rifting of the margin probably commenced in the Permian and culminated in a final phase from the Late Jurassic to Neocomian. This was followed by a period of intense erosion and peneplanation during the Neocomian. Formation of oceanic crust which now underlies the Cuvier and Perth Abyssal Plains, began in the Neocomian and was accompanied by a marine transgression which resulted in deposition of Aptian to Cenomanian shallow-marine clastic sediments over both the Carnarvon Terrace and Cuvier Abyssal Plain. After a hiatus, deposition of a post-Senonian shelf carbonate sequence commenced and has continued until the present day with only minor interruptions.The existence of a large trough of Mesozoic sediments that is probably a northwestern extension of the Abrolhos Sub-basin considerably upgrades the hydrocarbon potential of the southern Carnarvon Terrace. Traps along the possible offshore extension of the Rough Range Fault and Devonian reef complexes within the Palaeozoic high may also be prospective for hydrocarbons.
PETROLEUM GEOLOGY OF WESTERN NEW SOUTH WALES
Authors: Evans P. R.
Published: August 2017

The only area of Western New South Wales considered to have petroleum potential is the intracratonic, fault-bounded Darling Basin, which evolved during Late Silurian to Early Carboniferous time and which contains up to 7000 m of sediments. Initially deposition was controlled by a shallow marine transgression from the east. Regression during the Middle Devonian was followed by basin-wide extension of alluvial sedimentation, which prevailed until the Early Carboniferous. Strike slip movements during Late Devonian time along old basement trends fragmented the basin into distinct troughs. Movements along the same trends during the Carboniferous modified the troughs' configuration. Permian, Mesozoic and Cenozoic sag-like downwarps in various parts of the region had negligible effect on bedding attitudes.The only play of the Basin thought to have a chance for significant petroleum generation and entrapment lies in the Lower and (?) Middle Devonian, where marginal marine deposits flank highs created by strike slip movements. This play is regarded as one of high risk for modest returns, but its continued exploration seems warranted in view of proximity to markets and to the Moomba-Sydney pipeline.
NEW DEVELOPMENT OF THE TEALARC NATURAL GAS LIQUEFACTION PROCESS
Authors: Dufresne Jean-Pierre , Gauberthier Joseph , Schlatter Rene
Published: August 2017

Technip has experience in the LNG field obtained through the design and erection of two base load natural gas liquefaction plants in Algeria and the process licensing of 13 peak-shaving units mainly in North America.Through its operating experience of base-load plants and the research and development studies performed, Technip has improved the Tealarc liquefaction process with regard to the main criteria: efficiency, reliability, flexibility, simplicity and has also adopted the Tealarc process to the use of centrifugal compressors. In this case the Tealarc process is split into two different cycles, the first Tealarc cycle called "Precooling cycle" is used to partially condense the cryogenic fluid of the second Tealarc cycle called "Liquefaction cycle" which performs the condensation of the natural gas and the subcooling of LNG.This arrangement of the precooled Tealarc process allows the realisation of large capacity liquefaction trains while satisfying the limitation of the centrifugal compressorIn 1976 French and Italian experience in the LNG process sector were combined through a permanent joint-venture between Technip and Snam Progetti.
MAJOR PROJECTS AND THE ENVIRONMENT
Authors: Butters J. W.
Published: August 2017

The realisation that man needs to work with nature rather than against it indicates growing maturity and awareness in the community. However, in dealing with the environment we need moderation. We need to remind ourselves that "environmentalism" is neither a profession nor an exact science. Answers are rarely certainly right or certainly wrong. As with most natural problems the best answers are usually a reasonable compromise.The Moomba-Sydney Natural Gas Pipeline Project was delayed 18 months. Two public Environmental Inquiries were held resulting from pressure from environmental groups.Following political intervention the first Inquiry caused a reroute of the main trunk adding 90 km (56 mi.) to its length and seriously delaying its commencement so that inflationary effects, added to the cost of the longer route and its complete resurvey, caused additional cost to the project of over $100 million.The second Inquiry required such change of the pipeline fundamentals, despite three years of comprehensive interdepartmental discussions held to ensure agreement, as to render the lateral under review economically unfeasible in its present form. Its cost would be something like six times its original estimate.Similar inflationary effects and uncertainties afflicted the other lateral causing its deferment also. The final cost of completing the whole project initially estimated at $155 million would now be in excess of $320 million.These deferments sprang principally from the economic consequences of environmental and/or industrial uncertainties. The communities which would otherwise have benefited by immediate service from relatively pollution-free energy are thus denied access to it. The impact of this deferment upon their own future environment was not called to account in the Inquiries.
STRUCTURAL AND STRATIGRAPHIC EVOLUTION OF THE TARANAKI BASIN, OFFSHORE NORTH ISLAND, NEW ZEALAND
Authors: Pilaar W. F. H. , Wakefield L. L.
Published: August 2017

The Taranaki Basin contains the only commercial gas and condensate fields in New Zealand. Thirteen offshore wells have been drilled, three of which delineated the Maui Field while six deep tests have been drilled onshore, one of which discovered the Kapuni Field. The geology of the Taranaki Basin is synthesised into a transgressive stratigraphic framework which was modified by two tectonic phases, initial rifting and foundering, followed by wrench faulting. The basin consists of the Western Platform and Taranaki Graben Complex. The former was a relatively stable block throughout most of the Tertiary, only affected during Late Cretaceous to Eocene times by normal block faulting. The latter is bounded to the east by the Taranaki Fault Zone which was mainly active during the Miocene. To the west, the Graben Complex generally shallows across a series of en-echelon steep normal to reverse faults which often show drastic changes in throw over short distances.Upper Cretaceous coal measures were deposited in fault angle depressions. Marine sediments were deposited in western areas by Paleocene times. A regressive phase occurred during Eocene times when coal measures were deposited in southern and eastern areas. Quartzose sandstones of these coal measures are the reservoirs in the Kapuni and Maui Fields. In Late Eocene to Oligocene times, regional submergence recommenced and mainly calcareous sediments were deposited: pelagic -rich sediments in the west, neritic limestones, sandstones and mudstones in the south and east. With the development of the Taranaki Graben Complex from the Miocene onwards, sedimentary sequences consist of graben -fill mudstones and flysch, and prograding wedges comprising the continental shelf.
LATERAL AND VERTICAL RANK VARIATION: IMPLICATIONS FOR HYDROCARBON EXPLORATION
Authors: Kantsler A.J , Smith G. C. , Cook A. C.
Published: August 2017

Vitrinite reflectance measurements are used to determine the vertical and lateral patterns of rank variation within four Australian sedimentary basins. They are also used to estimate palaeotemperatures which, in conjunction with present well temperatures, allow an appraisal of the timing of coalification and of hydrocarbon generation and distribution.The Canning Basin has a pattern of significant pre-Jurassic coalification which was interrupted by widespread uplift and erosion in the Triassic. Mesozoic and Tertiary coalification is generally weak, resulting in a pattern of rank distribution unfavourable to oil occurrence but indicating some potential for gas. The Cooper Basin also has a depositional break in the Triassic, but the post-Triassic coalification is much more significant than in the Canning Basin. The major gas fields are in, or peripheral to, areas which underwent strong, early, telemagmatic coalification whereas the oil-prone Tirrawarra area is characterized by a marked rise in temperature in the late Tertiary. The deeper parts of the Bass Basin underwent early coalification and are in the zone of oil generation, while most of the remaining area is immature. Inshore areas of the Gippsland Basin are also characterized by early coalification. Areas which are further offshore are less affected by this phase of early maturation, but underwent rapid burial and a sharp rise in temperature in the late Tertiary.
STRUCTURE AND STRATIGRAPHY OF THE CEDUNA TERRACE REGION, GREAT AUSTRALIAN BIGHT BASIN
Authors: Fraser A. R. , Tilbury L. A.
Published: August 2017

The Ceduna Terrace is a bathymetric feature covering some 70,000 sq km, in the continental slope of South Australia. Its most gently sloping part lies between the 500 and 2500m isobaths, and is underlain by the main depocentre of the Great Australian Bight Basin.A systematic interpretation of the region has been made, based on 17,000 km of multi-channel seismic data from Shell surveys, 8000 km of single-channel seismic, gravity and magnetic data from the BMR Continental Margins Survey, and 6000 km of gravity and magnetic data from surveys by Lamont-Doherty Geological Observatory. Seismic ties were made to the wells Potoroo-1 and Platypus-1.Mapping of the key seismic horizons confirms the picture of the basin as a sedimentary wedge, more than 10 km thick, extending from the edge of the shelf to the continental rise. Three important unconformities can be mapped over a wide area and tied to Potoroo-1 well-a basement reflector separating Lower Proterozoic crystalline rocks of the Gawler Craton from an overlying, block-faulted sequence of mainly Lower to mid-Cretaceaus sediments; an unconformity at the base of an Upper Cretaceous sequence which includes a major prograded unit in the west; and a break-up unconformity at the base of a Tertiary marine transgressive sequence, that, in turn, is overlain by marine carbonate deposits. Widespread shallow marine sediments are believed to exist in the west of the basin, in both the Lower and Upper Cretaceous sequences.Structure is dominated by normal, west to NW trending, down-to-the-south faults, many of which are synsedimentary. Fault displacements are greatest beneath the shelf-break, where basement has been downthrown 5 to 6 km. Farther south, synsedimentary faulting has resulted in a marked thickening of both Upper and Lower Cretaceous sequences.The basin has been barely explored for hydrocarbons. Regional seismic coverage is good, but drilling in the main part of the basin is limited to one well on the northern margin. The petroleum potential of the western half of the basin is rated as good, in view of the interpreted existence of abundant marine source beds and the recognition of situations favourable for generation, migration and entrapment of hydrocarbons.
NEOCOMIAN EUSTATIC CHANGES — BIOSTRATIGRAPHIC EVIDENCE FROM THE CARNARVON BASIN
Authors: Wiseman J.F.
Published: August 2017

A fall in sea level of approximately 200m affected the northern Carnarvon Basin of Western Australia during the earliest Neocomian. This was followed by a brief lowstand and then a basin-wide flooding beginning in the Late Valanginian or Early Hauterivian. Maps showing the pattern of inundation as the sea level rose reflect the palaeotopography of the basin at the time. These maps are derived from the age of the base of the onlapping sequence, namely the Winning Group. The ages are based on a palynological zonation of the Neocomian to Early Aptian.
AN INVESTIGATION INTO DISCREPANCIES BETWEEN SONIC LOG AND SEISMIC CHECK SPOT VELOCITIES
Authors: Goetz J.F. , Dupal L. , Bowler J.
Published: August 2017

Well data, and in particular Sonic Logs, are the basis for calibration of seismic data leading to improved reservoir delineation. Sonic data are adjusted to match seismic times by comparison to check shots. Recent improvements in Sonic Logging tend to show that, on average, Sonic velocities are faster than seismic velocities. The main reason appears to be frequency dependance of velocities.
SIMULTANEOUS DRILLING AND PRODUCTION ON OFFSHORE PLATFORMS
Authors: Khurana A.K. , Irrgang H.R.
Published: August 2017

Simultaneous drilling and producing on offshore platforms is a standard worldwide practice and can be conducted safely with significant attendant benefits. These include timely procurement of critical reservoir data to ensure proper reservoir development and improvement in reservoir development economics related both to and near term production acceleration and potential improvement in ultimate recovery.Qualitative and quantitative assessments show that incremental risks associated with simultaneous drilling and production are small compared to the basic risks involved in offshore development drilling. The assessments have led to the identification of various specific safety practices which are recommended for simultaneous drilling and producing operations.The possibility of intersection between a drilling and a producing well is considered to be one of the major areas of concern in concurrent drilling and production. A statistical approach, based on probable directional survey errors, has been developed for determining the minimum safe measured separation between drilling and producing wells as a function of depth. All producing wells falling within this minimum safe distance from a drilling well must be shut-in below the deepest point of potential interference.Where possible the use of surface controlled subsurface safety valves (SSVs) for shutting-in completed and perforated wells to meet the minimum safe distance criterion is preferable to the more traditional practice of using wireline set tubing plugs. In addition to being much cheaper, the SSV method should render simultaneous drilling and production considerably safer by minimising the number of wireline operations; accordingly, directional well planning and the setting depth of SSVs should be such that the SSV is located below the deepest point of potential interference in as many cases as possible. In instances where the SSV is located above the deepest point of potential interference, tubing plugs will have to be set.
INDUSTRIAL RELATIONS — AN IMPORTANT ASPECT OF HYDROCARBON EXPLORATION AND DEVELOPMENT IN AUSTRALIA
Authors: Young D.H.
Published: August 2017

The unique Australian system of controlling industrial relations matters was created in the early 1900's against a background of disastrous national strikes in the 1890's and during the formation of the Commonwealth of Australia.The Australian Constitution was framed to include specific powers to protect the country and the general public from the consequences of industrial disputes between employers and employees by requiring conciliation processes to be followed and, if they failed, for compulsory arbitration of the dispute.The division of powers between the Commonwealth and State Governments causes complications and inconsistencies and has highlighted the intrusion of political considerations into industrial relations problems.The Commonwealth and most State Governments have created systems based on registered organisations of employers and employees. Registration is intended to create rights and obligations and to result in responsible bodies being subject to the enforcement procedures of the arbitration tribunals. Registration also delineates the scope of membership coverage and the industries in which the registered bodies may operate. In theory, there should be no overlapping of registered constitutions and therefore no demarcation or "jurisdictional" type disputes. A major problem has been created by registration based on crafts or occupations instead of on an industry basis. This has resulted in up to 15 or more unions having members in, even, medium sized establishments.The recent trend has been towards amalgamations of employer and employee organisations and the formation of "peak" employer and employee councils-the CAI and the ACTU. The activities of these Councils is leading to a centralised system of wage fixation and towards common standards of conditions of employment with deviations only to meet special circumstances. This tends to cause any change in wage rates or conditions of employment in any one area to "flow" into other areas and industries on a "comparative wage justice" basis.The expansion of onshore exploration and development of the hydrocarbons industry into offshore areas has resulted in more unions becoming involved in the industry, with inconsistencies between land based and maritime unions in approaches to construction and production work.Much work will be required by employers and their organisations within the hydrocarbons industry to overcome the industrial relations difficulties that will arise at interfaces between them and other well established industries.
THE TOOWOOMBA - CHARLEVILLE LINEAMENT IN SOUTHERN QUEENSLAND
Authors: O'Driscoll E.S.T. , Keenihan S.L.
Published: August 2017

Recent structural studies have revealed the presence of a major linear feature which crosses southern Queensland in a west-northwesterly direction. This feature, designated the Toowoomba-Charleville Lineament, is thought to correspond to a zone of disturbance or discontinuity in the basement. As such, it has influenced basement relief and the evolution and configuration of the Surat, Adavale and northern Cooper Basins. The specific effects of the Toowoomba-Charleville Lineament are considered in conjunction with the well established Darling River Lineament with particular reference to the Surat Basin. The directions of these two continental features are parallel to major global trends, suggesting that they are part of a larger system which appears to be a fundamental pattern of dislocation in the earth's crust.
NEW DEVELOPMENT TECHNIQUES IN BASS STRAIT
Authors: Koroknay S.J.
Published: August 2017

A total of 114 exploratory wells have been drilled in Bass Strait by Esso Australia Ltd. Prior to 1979 discoveries of hydrocarbon accumulations have been developed exclusively by the use of conventional platforms. During 1979 the use of subsea completions was introduced as a development technique. In addition, areal coverage by conventional platform development was extended by the drilling of a very highly deviated directional well.Cobia-2, the first subsea completion in Bass Strait, was brought on production on June 30, 1979. During the installation of the subsea completion two 90 mm flowlines were successfully laid using the reel pipe-laying technique from the back of a workboat. Production of the well has been successfully controlled by one of the few operational electrohydraulic control systems in the world. Numerous pumpdown tool operations have been completed for dewaxing of flowlines. While on production the well has been producing 450 kl per day, flowing to the Mackerel ‘A’ platform.In the early 1970's the location of platforms was determined by using a 45° to 50° angle of deviation limit for directional wells. This limit was gradually extended with each platform until a very significant change was achieved with the Mackerel A-14 well drilled with an average deviation angle of 69°. The significance of following good basic drilling practices was accentuated while attempting to reach a true vertical depth of approximately 2 400 metres by drilling 5 200 metres of directional hole. Production was commenced from this well on November 30, 1979.These two techniques will pave the way for increased recovery in the 1980's, especially from the smaller reservoirs in Bass Strait. Perhaps more importantly, these techniques will have significance in the deeper water areas to which the industry is currently headed.
APPLICATION OF COMPUTERIZED GAS CHROMATOGRAPHY – MASS SPECTROMETRY TO OIL EXPLORATION IN AUSTRALIA
Authors: Philp R.P. , Gilbert T.D.
Published: August 2017

Computerized gas chromatography-mass spectrometry (C-GC-MS) is a sophisticated analytical technique capable of identifying very small quantities of individual components in complex mixtures of organic compounds. One field in which C-GC-MS can play an extremely important role is correlation studies of crude oils and source rocks.In C-GC-MS analyses, compounds present in the crude oil or source rock extract are first separated by the gas chromatograph and then fragmented and ionized in the ion source of the mass spectrometer. The mass and relative intensities of the ions formed are recorded by the computer. Normally the masses of one or two specific fragments can be used to distinguish as particular class of compounds, a technique that is particularly useful for crude oil correlation studies.Comparison of mass fragmentograms for different oils yields information about their sources. Identical fragmentograms for ion characteristics of certain classes of "biological marker" compounds imply that the distribution of compounds in the oils is identical and hence that the oils had the same or very similar sources.Results of C-GC-MS analysis of four oils from the Gippsland Basin indicate that, despite varying degrees of biodegradation, the oils had the same or very similar source materials. Similarly C-GC-MS analysis of the Barrow Jurassic and Windalia oils from the Carnarvon Basin provides evidence to support the theory that these two oils had the same or very similar source material.
WELLSITE COMPUTER INTERPRETATION USING THE DIRECT DIGITAL LASER LOGGING SYSTEM
Authors: White L.
Published: August 2017

The Direct Digital Laser logging system is a fully self-contained logging unit designed to improve operating techniques and reduce rig time required for logging; this system increases data quality, eliminates human error and provides accurate digital recording of data while producing an instant hard copy output. The computer, programmed to handle the logging of each downhole tool combination, is also used to process this data at the well site and provide on-site interpretations to assist in well evaluation and decision-making.
ORIGIN OF THE WINDALIA OIL, BARROW ISLAND, WESTERN AUSTRALIA
Authors: Alexander R. , Kagi R. , Woodhouse G.
Published: August 2017

Although Windalia oil from Barrow Island, Western Australia is deficient in n-alkanes most other chemical properties of this crude are not characteristic of typical bacterially-altered crudes. In this study geochemical properties such as the alkane, aromatic and NSO content, sulphur content, level of maturity, API gravity, n-alkane distribution, and overall molecular weight distribution are compared for Windalia oil and typical bacterially-altered crude oils. In addition, the geological history of Barrow Island is considered to assess whether the Windalia reservoir has been flushed with meteoric waters.To investigate this problem further the gas chromatographic distribution of compounds in both the whole crudes and the aromatic fractions are compared for Mardie and Windalia oils. Mardie is a bacterially-altered oil located near Barrow Island. These distributions further support the contention that Windalia oil is not bacterially altered.Carbon isotope "petroleum type-curves", presented for Windalia, Mardie and the paraffinic Jurassic oil from Barrow Island, suggest that there is no genetic relationship between Windalia and the Jurassic oil, but that a strong relationship exists between Mardie and Windalia oil. Therefore, Windalia may be a parent of the Mardie oil and not an altered Jurassic oil.Because geochemical and geological evidence is inconsistent with the contention that Windalia oil is bacterially altered, an alternative mode of formation is proposed which involves : (a) early migration; (b) burial of the sediments to depths greater than their present depths; (c) reservoir catalysis; and (d) uplift and subsequent weathering of the sediments.