bluuebunny/crossref_metadata_2025 huggingface dataset:
HYDROCARBON GENERATION IN THE FLY LAKE—BROLGA AREA OF THE COOPER BASIN
Authors: Smyth Michelle
Published: August 2017

The Cooper Basin is a major gas producing basin in Australia. Organic material in sediments from its Permian coal measures has been studied using transmitted, reflected and fluorescent light microscope techniques of analysis. In the Fly Lake—Brolga area, of the Patchawarra Trough, Cooper Basin, the interseam sediments of the Patchawarra Formation contain three types of kerogen or dispersed organic matter (d.o.m.): exinitic, vitrinitic and inertinitic. Exinitic d.o.m. is most abundant near the top of the Formation, vitrinitic d.o.m. is more abundant in the middle and lower parts of it, and inertinitic d.o.m. occurs throughout.A correlation between the type of d.o.m. in the sediments and the petrography of associated coals is emerging. Exinitic d.o.m. appears to be associated with coals that have high vitrite-plus-clarite contents, whereas vitrinitic d.o.m. is associated with high "intermediates" coals. Further examples are needed to establish these relationships more firmly.On the basis of results of coal petrographic studies in other Australian Permian sedimentary basins, depositional environments have been proposed for the coal seams in the Fly Lake—Brolga area. These environments are compared with those proposed by Thornton (1978) using the clastic sediments of the Patchawarra Formation.
ONE-ATMOSPHERE PRODUCTION SYSTEMS FOR USE IN DEEP WATER
Authors: Cochrane Paul B.
Published: August 2017

The establishment of a joint industry sponsored subsea production system development program in early 1973 has resulted in the development of field-proven systems for the subsea production of oil and gas using the one atmosphere chamber concept.The program was completed in mid 1978 with the development of a deep-water multi-well drilling and producing station for the subsea production of oil and gas. Deep water is used here to refer to 3000 ft (915 m) and beyond. This study has resulted in equipment designs to provide for:A multi-well drilling and producing template to allow drilling and completion of approximately ten wells from a single rig location.Commingling of production from the wells into a common manifold chamber without laying flow lines.Connection of the production, service and electrical lines through a production riser, remotely located from the template wells, to a floating facility.Installation and servicing of subsea equipment using a one-atmosphere service system for deep water.The development of the deepwater system was preceded by the design, installation and operation of shallow-water equivalents.In October 1972, a one-atmosphere wellhead chamber was installed on a subsea well in 37S ft (114 m) of water in the Main Pass 290 field, offshore Louisiana. Subsequently, a one- atmosphere subsea manifold center designed to serve two subsea wells, completed with one-atmosphere wellhead chambers and one platform well, was installed. Since the August 1976 start-up of this subsea manifold center system, more than 300,000 barrels of oil and 680,000 MSCF of gas have been produced.
TRIASSIC-JURASSIC DEPOSITIONAL HISTORY OF THE DAMPIER AND BEAGLE SUB-BASINS, NORTHWEST SHELF OF AUSTRALIA
Authors: Crostella A. , Barter T.
Published: August 2017

Very large gas accumulations were discovered in the Dampier Sub-basin on the Northwest Shelf of Australia during the early 1970's. The majority of the reservoirs are fluvial and marginal marine sandstones within a thick intra-cratonic clastic sequence of Early Triassic to Middle Jurassic age. Parts of this succession have been penetrated by more than 60 wells within the Dampier Sub-basin and the adjacent Beagle and Barrow Sub-basins.Broad regional palaeoenvironmental episodes have been established using oriented core supplemented by seismic, palaeontologic and wireline log data. The earliest episode was an Early to Middle Triassic transgressive-regressive cycle which led to marine and marginal marine deposition, followed during the Middle to Late Triassic by dominantly fluvial deposition. A transgression began in the early Rhaetian, characterised by deltaic, estuarine, lagoonal and coastal sedimentation which gave way to fully marine conditions during the Early Jurassic (Hettangian); this was followed by a regressive cycle.A regional tectonic episode followed which resulted in development of troughs, and brought about associated extensional faulting. Marine conditions which typified the Early Jurassic (Sinemurian) persisted until the beginning of the Middle Jurassic (Bajocian) in the Dampier Sub-basin, but passed rapidly to a fluvio-deltaic cycle in the Beagle Sub-basin. Regressive conditions extended gradually westward until sedimentation was interrupted by the onset of major continental break-up toward the end of the Middle Jurassic.The deposition of an alternating sequence of thick shale and sand during mainly restricted marine and continental conditions has provided the area with potential source and reservoir rocks.
GEOCHEMISTRY AND SP - RESISTIVITY CALIBRATION OF SUBSURFACE WATERS - SURAT BASIN AREA
Authors: Porter C.R.
Published: August 2017

Waters in Early Jurassic strata in the interval pre-Jurassic unconformity to Evergreen Resistivity Marker (ERM) of the Surat Basin and in Triassic Showgrounds Sandstone of the underlying Bowen Basin contain solutions of sodium bicarbonate and sodium chloride in varying proportions. Geochemical classification indicates a range of genetic water types from artesian bicarbonate waters to the more stagnant chloride-sulphate waters. In terms of salinity, waters of the Bowen-Surat Basins range from fresh to brackish and are less than 10000 ppm sodium chloride equivalent concentration.Significant differences in geochemistry of the waters are noted between the Showgrounds Sandstone, and sandstones within the intervals, pre-Jurassic unconformity to Marker 8 (Precipice Sandstone) and Marker 8 to ERM (Evergreen Formation). These differences facilitate the calibration of the measured water resistivity (Rw) values with values (Rwe) derived from the Self Potential log.Formation water characteristics such as chloride concentration and sodium chloride equivalent concentration are useful tools in the search for hydrocarbons.
ORGANIC MATTER IN OIL SHALES
Authors: Hutton A.C. , Kantsler A.J. , Cook A.C. , McKirdy D.M.
Published: August 2017

The Tertiary oil-shale deposits at Rundle in Queensland and of the Green River Formation in the western USA, together with Mesozoic deposits such as those at Julia Creek in Queensland, offer prospects of competitive recovery cost through the use of large-scale mining methods or the use of in situ processing.A framework for the classification of oil shales is proposed, based on the origin and properties of the organic matter. The organic matter in most Palaeozoic oil shales is dominantly large, discretely occurring algal bodies, referred to as alginite A. However, Tertiary oil shales of northeastern Australia are chiefly composed of numerous very thin laminae of organic matter cryptically-interbedded with mineral matter. Because the present maceral nomenclature does not adequately encompass the morphological and optical properties of most organic matter in oil shales, it is proposed to use the term alginite B for finely lamellar alginite, and the term lamosites (laminated oil shales) for oil shales which contain alginite B as their dominant organic constituent. In the Julia Creek oil shale the organic matter is very fine-grained and contains some alginite B but has a higher content of alginite A and accordingly is assigned to a suite of oil shales of mixed origin.Petrological and chemical techniques are both useful in identifying the nature and diversity of organic matter in oil shales and in assessing the environments in which they were formed. Such an understanding is necessary to develop exploration concepts for oil shales.
A GUIDELINELESS TREE AND A FLOWLINE CONNECTION SYSTEM FOR DEEPWATER PRODUCTION
Authors: Henderson H.O.
Published: August 2017

The advent of dynamically-positioned drillships and guidelineless drilling in the early 1970's has extended the search for hydrocarbons into waters which are too deep for conventional mooring. To meet the economic requirements to produce discovery wells in this type of exploratory drilling, a single vessel is used to drill and complete a subsea well and to lay the flowlines without the use of guidelines or intervention by divers.Flexible flowlines are reeled on the deck of the drillship and laid away from an extension of the wellhead prior to the installation of the tubing hanger and xmas tree. Each piece of equipment is aligned and oriented when it is landed. The xmas tree is equipped for the use of TFL pumpdown tools in maintaining the well while producing. In case of damage to a flowline, replacement is made by recovering the flowling guide funnel and wellhead extension.
ADVANTAGES OF ENHANCED DATA LOGGING
Authors: Wiltshire M.J.
Published: August 2017

Rapid technologic evolution in the period from about 1955 to 1966 has been followed by considerable developments in exploration techniques. In recent years sophisticated data gathering and processing systems in seismic, gravity and magnetic methods, and in wireline logging, have become routine.The validity of interpretations drawn from such data is critically dependent on the care exercised at the data acquisition stage. Because of generally large subsequent processing costs, there is now considerable emphasis on in-field verification of acquisition procedures by highly experienced explorationists.A notable exception generally occurs during the drilling stages of an exploration programme. At present, such data acquisition is generally only carried out on relatively high cost offshore operations where it was first employed for safety reasons. However, geologists of limited experience generally still are given the responsibility of on-site verification of data.It is possible now to monitor fully and digitally record all data, control and optimize drilling parameters and economics, and, in so doing, obtain data which may subsequently be used as basic input to more complete section evaluation.Tangible benefits arise in the following areas : (a) increased drilling efficiencies generally lead to a significant reduction in total cost per foot; (b) substantial improvements in primary and secondary safety during drilling.Intangible benefits which may arise include : (a) direct interpretation of wireline logs and drilling parameter logs to yield quantitative source richness (TOC) and maturation (LOM) of shales; (b) improved interpretation of reservoir properties to allow better prediction of ultimate performance and superior design of stimulation programmes.
DENISON TROUGH, QUEENSLAND – NEW SEISMIC INFORMATION AND ITS HYDROCARBON IMPLICATIONS
Authors: Nelson A.W. , Bauer J.A.
Published: August 2017

New data from a digital six-fold CDP seismic survey in the Permo-Triassic Denison Trough, Queensland by the Bureau of Mineral Resources in conjunction with the Geological Survey of Queensland are markedly better than the old. They improve the hydrocarbon prospects of the trough by showing (a) structures within the Reids Dome Beds which have clearly formed early in the history of the trough, including one with a probable flat spot, (b) pinchouts in the Reids Dome Beds and younger units, and (c) pronounced faulting which occurred at the commencement of Cattle Creek Formation deposition. Major thrusting is shown to have occurred on the Merivale Fault during Middle to Late Triassic, and a conjugate thrust fault is identified. Localised faulting of known gas fields is suspected. A reflection within the Black Alley Shale and lower Bandanna Formation interval showing angular discordance with the formation boundaries is thought to arise from a tuff band marking an isochronous surface; this establishes the direction of progradation of the upper Black Alley Shale and Bandanna Formation. The overall structure of the trough is considered to be less complex than previously thought. In the light of the much improved seismic data, a reassessment of hydrocarbon plays in the Denison Trough appears warranted.
REGIONAL FACIES AND GEOCHEMICAL EVALUATION OF THE SOUTHERN DENISON TROUGH, QUEENSLAND
Authors: Jackson K.S. , Hawkins P.J. , Bennett A.J.R.
Published: August 2017

Results of geochemical investigations by the Bureau of Mineral Resources (BMR) and the Commonwealth Scientific and Industrial Research Organisation (CSIRO) indicate significant potential for hydrocarbon source throughout the Permian sequence with the Cattle Creek Formation (shallow shelf mudstone and shale facies, and prodelta mudstone facies) and the Reids Dome Beds (fluvial flood basin facies) constituting the most favourable source rock facies. The source rock facies comprise dominantly humic organic matter indicating that the Permian source is mainly gas-prone. The existing mature organic zone within the trough encompasses much of the Cattle Creek Formation and a section of the Reids Dome Beds; this suggests that present-day hydrocarbon generation may be taking place within these source rocks.A complementary regional facies analysis by the Geological Survey of Queensland (GSQ) demonstrated a relationship between hydrocarbon-bearing reservoirs and facies types. Clearly distributary channel, tidal, beach and barrier bar facies constitute the most favourable reservoir facies. Within the interval covered by the Cattle Creek Formation and Aldebaran Sandstone, juxtaposition of source and reservoir facies has been recognised and could present favourable stratigraphic traps. Three zones are recognised:an area extending from Rolleston to Westgrove;within the Kildare area; andan area extending from GSQ Taroom 10 to AAO Kia Ora 1.These zones deserve further consideration. Results of this integrated investigation lends optimism to further exploration.
A REVIEW OF RECENT GEOLOGICAL WORK IN THE OFFICER BASIN, SOUTH AUSTRALIA
Authors: Pitt G.M. , Benbow M.C. , Youngs Bridget C.
Published: August 2017

The Officer Basin of South and Western Australia, in its broadest definition, contains a sequence of Late Proterozoic to pre-Permian strata with an unknown number of stratigraphic breaks. Recent investigations by the South Australian Department of Mines and Energy (SADME), which included helicopter-based geological surveys and stratigraphic drilling, have upgraded the petroleum potential of the basin.SADME Byilkaoora-1, drilled in the northeastern Officer Basin in 1979, contained hydrocarbon shows in the form of oil exuding from partly sealed vugs and fractures in argillaceous carbonates. Equivalent carbonates were intersected in SADME Marla-1A and 1B. Previously, in 1976, SADME Murnaroo-1 encountered shales and carbonates with moderate organic carbon content overlying a thick potential reservoir sandstone, while SADME Wilkinson-1, drilled in 1978, contained a carbonate sequence with marginally mature to mature oil-prone source rocks. Acritarchs extracted from the last mentioned carbonates indicate an Early Cambrian age.All ?Cambrian carbonate sequences recognised to date in the Officer Basin of South Australia are correlated with the Observatory Hill Beds, which are now considered to be the major potential source of petroleum in the eastern Officer Basin.
COMPREHENSIVE ANALYSIS OF DRILLSTEM TEST DATA WITH THE AID OF TYPE CURVES
Authors: Sinha B.K. , Montgomery J.M.
Published: August 2017

A substantial percentage of drillstem tests cannot be analysed by convential methods due to insufficient data. Numerous tests have been analysed by several published type curves.In this paper, many examples are included where the application of the appropriate type curve aided in providing correct analysis of data which otherwise may have been misinterpreted.
THE PETROLEUM GEOLOGY OF THE ONSHORE BONAPARTE BASIN
Authors: Laws R.
Published: August 2017

The Bonaparte Basin formed in the Early-Mid Palaeozoic as a result of divergent left-lateral wrenching within the northeast trending Halls Creek Mobile Zone. The main phase of deposition in the onshore portion of the basin occurred in the Late Devonian to Early Carboniferous, when over 5 000 m of sediments were laid down. Extensive outcrops around the basin margins demonstrate complex facies relationships and the continuance of wrench faulting during deposition.A reef complex of Late Devonian age fringes the western basin margin. In the basin centre, shales and silts of the Bonaparte Beds form the lateral equivalent of the various facies cropping out around the flanks.A northeast trending basement high occurs in the eastern Bonaparte Basin. A barrier reef complex is predicted to cap the ridge with subtidal and estuarine sediments deposited in the shallow water conditions that existed east of the barrier.Oil shows have been encountered in shallow core holes drilled around the basin margins. Source rock analyses have also highlighted the potential of the basinal shales and lagoonal carbonates to produce hydrocarbons. Gas has flowed on test from thin sandstones within the Bonaparte Beds in two of the wells drilled onshore.Reservoirs are predicted to be present in sandstones of the Bonaparte Beds and also where secondary porosity is developed in carbonates, especially those of the reef complex.Although subsurface structural data are sparse, anticlines are mapped from outcrop data and structures related to both faulting and compaction over basement highs are predicted to occur.
THE GEOLOGY OF THE CONDOR OIL SHALE DEPOSIT—ONSHORE HILLSBOROUGH BASIN
Authors: Green P. W. , Bateman R. J.
Published: August 2017

The Condor oil shale deposit lies in sediments of the Tertiary Hillsborough Basin, on the north-central Queensland coast. The basin is an elongate, southeast-trending graben, most of which lies under Repulse Bay and the Hillsborough Channel. Palaeozoic volcanics and sediments and Palaeozoic- Mesozoic intrusives form the basement. Current drilling has been conducted onshore and is concentrated on the south-western flank of the basin. Beneath a veneer of Quaternary alluvial sand and clay, averaging 20 m thick, the drilling has differentiated six informal stratigraphic units in the Tertiary sequence. The 'sandstone unit', which is at the base of the sequence and is at least 140 m thick, consists of fine to very coarse sandstone and may be coarsening towards the southeast. The overlying 'carbonaceous unit' (10-50 m) comprises sandstone, coal and carbonaceous shale, and loses its identity in the southeast.Abruptly overlying these two units is a sequence of entirely different character. The 'brownish black' and the 'brown oil shale units', totalling about 400 m, comprise massive lamosite. The 'transitional unit (80-180 ) consists of thin graded sandstone beds with laminated oil shale and siltstone. The 'upper unit', at least 500 m thick is similar, but contains a higher proportion of sandstone in thicker beds.Bedding dips regularly at 14°-16° to the northeast, disrupted in part by a parallel series of normal, west-dipping, strike faults, which die out towards the southeast. Towards the north of the project area these faults appear to be offset by a major east-west structure, probably a syndepositional fault. A wedge of sandstone appears within the 'brown oil shale unit' immediately north of the structure's inferred position. The 'sandstone' and 'carbonaceous units' were probably deposited in fluvial and swampy-deltaic environments respectively. The oil shale was deposited in a shallow, saline and euxinic lake or bay, while the sandstone intercalations of the upper two units, derived from the north and northeast, indicate later regression of the lake or bay.The lower part of the 'brown oil shale' and upper part of the 'brownish black' units aggregate about 200 m and constitute the main zone of interest. This zone has an average grade of 63.5 litres oil/tonne of shale oil at zero per cent moisture (LTOM). Using a cut-off grade of 40 LTOM the resources has been calculated at 6.25 billion barrels of in situ shale oil.
CITY GATE NATURAL GAS PRICING IN AUSTRALIA
Authors: McCaul B. P.
Published: August 2017

Natural gas price structures in Australia vary widely from state to state. Long-term low-base-price contracts with inadequate, but freely entered into, price escalation clauses are the main cause of this discrepancy.Natural gas pricing structures in Australia evolved from the cost of alternate energy forms or market conditions prior to 1970, when the first contracts were negotiated. Major changes in the pricing environment have since occurred. New factors include substantial Government control or influence and the development of a monopsonistic market in place of the previous situation where there were alternative sales outlets.The influence of gas utilities on the overall gas price structure has changed dramatically in the last 10 years.Explorers are looking to new marketing and gas use concepts to obtain a more equitable return for their risk than the present monopsonistic market promises to allow. They do not accept that the reward for success should reside with the gas utilities as it currently does, rather than with them as the original risk takers.The industry should itself make changes in current gas pricing structures to correct inequitable and anomalous situations. This would preempt probable Government interference.A free market system is the best long-term policy to ensure efficient exploration and economic use of natural gas.
FINANCING AUSTRALIAN ENERGY DEVELOPMENT AN INTERNATIONAL VIEW
Authors: Stabback J. G. , Waddingham D. G.
Published: August 2017

In an energy-short world, escalating inflation and rising energy prices, the development of Australia's abundant natural resources will not only propel the economy forward through the 1980's, but will also significantly add to the world's available energy resources and lessen the upward pressure on oil prices.Enormous resources of coal and uranium are available in Australia together with modest reserves of crude oil and natural gas. The cost of developing these resources could well exceed $50 billion over the next decade. Because of the large scale and higher cost of developing these resources, increasing use of overseas funding will be needed unless taxation policies are altered in Australia to provide more internal cash flow. Joint ventures with international firms and project financing methods will be used more extensively in future to develop Australia's energy resources.
CUTTAPIRRIE 1—AN OIL DISCOVERY IN THE EARLY JURASSIC OF THE EROMANGA BASIN
Authors: Barr T. M. , Youngs Bridget C.
Published: August 2017

Cuttapirrie 1 discovered a significant oil accumulation at a depth of 8 016 ft in the Early Jurassic Hutton Sandstone of the Eromanga Basin. In addition, it discovered a small gas accumulation at 9 386 ft in the underlying Permo-Triassic Cooper Basin of South Australia. The well was 210 km from the nearest Jurassic oil field and 30 km from the nearest gas field when it was drilled.
DULLINGARI NORTH 1 AN OIL DISCOVERY IN THE MURTA MEMBER OF THE EROMANGA BASIN
Authors: Mount T. J.
Published: August 2017

Dullingari North 1 discovered oil in thin sandstone in the Murta Member of the Mooga Formation in the Dullingari area.The well is about 70 km east of Moomba in northeastern South Australia.The oil flow was the first from the upper Mooga Formation (Late Jurassic-Early Cretaceous) and the reservoirs are the youngest known oil producers in the western Eromanga Basin.
DIAGENESIS AND RESERVOIR QUALITY, TOOLACHEE FORMATION, COOPER BASIN
Authors: Martin K. R. , Hamilton N. J.
Published: August 2017

A preliminary petrological study of the Toolachee Formation in three Cooper Basin wells indicates that the intensity of diagenetic changes in the sandstones is the main factor influencing reservoir quality.Reduction of primary porosity occurs as a result of silica cementation as quartz overgrowths, dissolution of quartz grains forming microstylolitic grain contacts, authigenic clay mineral formation accompanying breakdown of chemically unstable grains, and cementation by siderite. Secondary porosity is erratically developed as a result of dissolution of some unstable grains particularly in rocks showing an advanced state of diagenetic alteration. High permeabilities are obtained only from those sandstones where significant primary porosity is still retained.Removal of chemically unstable grains during diagenesis has resulted in the formation of mineralogically mature sandstones, which consist almost entirely of quartz and clay minerals. The only other detrital components present are chemically resistant minerals such as muscovite or rock fragments composed of these resistant minerals.A relatively simple relationship of increasing intensity of diagenetic processes with increasing depth of burial may exist for the Toolachee Formation in the Cooper Basin.
THE LITHO-DENSITY* LOG
Authors: Bowler J.
Published: August 2017

The Litho-Density Log (LDT) measures a new formation parameter, Pe, the effective photoelectron cross-section. This measurement is made at the same time as the measurement of bulk density, ρb. The equipment is com bined with Gamma Ray and Compensated Neutron Loqqinq (CNL*) devices.Pe is a function of Z. the effective atomic number. The Z of a formation determines its chemical content and therefore its lithology.The effect of gas on the Pe measurement is almost neglible so it becomes a good lithology Indicator in non-shaly gas-bearing reservoirs. As a result, it provides a means for confirming porosity determinations made with corrected bulk density and CNL porosity data.The radioactive logging parameters for a number of sedimentary minerals have recently been computed. With this knowledge and the addition of the Pe measurement it is possible to discriminate between tight streaks and heavy minerals such as siderite.A number of clays, such as glauconite, may be identifiable with cross-plot methods. Knowledge of the presence of glauconite, which is thought to be formed in shallow marine waters, can be useful in establishing depositional environments.If a Natural Gamma Ray Spectroscopy (NGS*) Log is available, additional cross-plots are proposed which will enhance the identification of clay mineralsSeveral of the proposed interpretation techniques are illustrated with data from Australian and other well logs.*Mark of Schlumberger
THE CAMBRIAN PALAEOGEOGRAPHY OF AUSTRALIA AND OPPORTUNITIES FOR PETROLEUM EXPLORATION
Authors: Cook Peter J.
Published: August 2017

As part of a larger project to re-evaluate the petroleum potential of Australia, it was considered necessary to produce a series of Cambrian palaeogeographic maps. This required the compilation and correlation of a large number of stratigraphic columns, the delineation of sedimentologlcally-significant time intervals, the production of data maps for these same time intervals, and the development of a Cambrian 'tectonic' map. This palaeogeographic study was not undertaken to establish precise exploration targets. However, it does provide new information on where many of the essential components are, what age they are, and why they are there, and as such is a valuable tool in the overall exploration and resource evaluation strategy.The six palaeogeographic maps finally produced illustrate events involving continental drift, tectonics, and climatic and sea-level variations, over a period of 70 million years. Together, these events produced marked changes in the palaeogeography and depositional environments, which in turn profoundly affected the type and distribution of sediments being deposited on and around the palaeo-continent during the Cambrian. Using the palaeogeographic maps and the data accumulated for the project, it is possible to demonstrate that organic-rich sediments, with the potential to be petroleum source rocks, were relatively common during the Cambrian, especially on the eastern cratonic margin during the Lower Cambrian (Officer and possible Amadeus Basins) and the Middle Cambrian (Georgina Basin). There may also be some suitable petroleum source rocks in the Ord Basin. Limestones and dolomites, some of which may constitute potential reservoir rocks, were deposited in a number of Cambrian intracratonic basins (Amadeus, Georgina Basins) and on the shelf (Cooper Basin). Cambrian sandstones in Australia are commonly poor reservoir rocks, but where they have been subjected to shore-line or shelf 'clean-up', for example during the Middle and Upper Cambrian on the northwest side of the craton (Bonaparte Gulf Basin), there may be some potential reservoir rocks. Some sandstones may also be present on the south side of the Cooper Basin. Fine-grained impermeable sediments (potential cap rocks) were deposited throughout the Cambrian, but evaporites were most common during the Early and lower Middle Cambrian. Synsedimentary tectonics may have produced structural and stratigraphlc traps, and a major phase of karsting occurred in the Cambrian. Therefore, the Cambrian of Australia is believed to have many of the prerequisites for the generation, migration and entrapment of hydrocarbons. Especially favourable areas for these features may lie to the southeast of the Georgina Basin and in the offshore region northwest of the Ord and Bonaparte Gulf Basins.
ANCHORING OF STRUCTURES IN DEEP WATER
Authors: Moe Einar Tore , Olsen Odd A.
Published: August 2017

The oil and gas exploration industry continually discovers energy resources at greater water depths, and in many of the structures now being designed for offshore oil and gas production the anchoring system is one of the key components, having significant influence on operational characteristics as well as safety.The best possible understanding of the problems involved in anchoring is therefore essential, and an evaluation of a design for deep-water long-term anchoring should include:evaluation of possible excitation sources at actual site (wind, waves, current)dynamic analysis of the structure and mooring linesevaluation of soil properties and anchor behaviourevaluation of fatigue strength of mooring linesevaluation of conditions for corrosion and corrosion protection.In this paper 'the state of the art' within these problem areas is discussed. Sample calculations of global and local dynamics of the mooring lines are compared with results from conventional quasistatic analysis to demonstrate the importance of taking into account dynamic phenomena and oscillations caused by wind, waves and current action. Areas for further research are also discussed.
PALAEOTECTONIC EVOLUTION AND HYDROCARBON GENESIS OF THE CENTRAL EXMOUTH PLATEAU
Authors: Barber Peter M.
Published: August 2017

In the wake of high industry optimism for the discovery of commercially viable hydrocarbons on the Exmouth Plateau, drilling of three wells by the Phillips Group revealed the presence of noncommercial quantities of gas. Expectations were originally based on the generation of oil from Upper Jurassic and Neocomian shales in the Kangaroo Trough and subsequent migration into Triassic and Jurassic tilted fault blocks on the Exmouth Plateau High, tested by the Jupiter 1 and Mercury 1 wells. In both these wells, and at the Saturn 1 location subsequently drilled in the Kangaroo Trough, the Upper Triassic, Jurassic and Cretaceous sections were found to be immature and incapable of generating hydrocarbons. Most hydrocarbon shows on the Exmouth Plateau possibly originated from a deep (5.5 km) overmature gas source, probably Lower Triassic and Permian shales. Deep tapping of the source beds by faults bounding the tilted fault block structures has enabled gas to migrate.Integrated palaeotectonic and thermal maturation studies indicate a direct link between the hydrocarbon grade and its subsequent expulsion and entrapment. The absence of much of the Jurassic cover due to erosion and/or non-deposition allowed early and mature phase hydrocarbons being generated from the Permian and Lower Triassic to escape. With increasing depth of burial and concomitant overmature hydrocarbon genesis during the Cenozoic era, further leakage was caused by upward perpetuation and regeneration of the fault conduits, breaching the Lower Cretaceous and younger sealing units. Effective trapping usually occurs only where overmature gas is trapped by fault-independent closure immediately beneath the Callovian break-up unconformity, such as at Jupiter 1 and Saturn 1.The lack of major liquid hydrocarbons is attributed to unfavourable source rocks, inadequate burial history and an historically low geothermal gradient, the effect of which is further compounded by the cooling effect of water depths greater than 1000 m.
HYDROCARBON HABITAT OF THE SURAT/BOWEN BASIN
Authors: Thomas B. M. , Osborne D. G. , Wright A. J.
Published: August 2017

Ever since the early discoveries at Cabawin (1960) and Moonie (1961), the origin of oil and gas in the Surat/Bowen Basin has been a subject of speculation. Hydrocarbons have been found in reservoirs ranging in age from Permian to Early Jurassic; even fractured pre-Permian 'basement' rocks have occasionally recorded shows.Recent geochemical studies have identified rich source rocks within the Jurassic, Triassic and Permian sequences. The Middle Jurassic Walloon Coal Measures are thermally immature throughout the Surat Basin and are unlikely to have generated significant amounts of hydrocarbons. Lower Jurassic Evergreen Formation source rocks have reached 'nominal early maturity' (VR = 0.6) in parts of the basin. The Middle Triassic Moolayember Formation lies within the oil generation zone in the northern Taroom Trough. However, no oil has yet been confidently correlated with either a Jurassic or a Triassic source. On geochemical and geological grounds it is likely that most, if not all, of the hydrocarbons discovered to date were generated from Permian source rocks.The probability of finding gas as well as oil in Permian, Triassic or Jurassic reservoirs increases from south to north, in accord with organic maturity trends in the Permian of the Taroom Trough. On the narrow thrust-bounded eastern flank, vertical migration has occurred, resulting in oilfields at Moonie and Bennett. In contrast, extensive lateral migration of hydrocarbons across the gentle western flank of the basin is indicated by numerous small oil and gas fields on the Roma Shelf and Wunger Ridge.
DEVONIAN REEF PROSPECTS IN THE CANNING BASIN: IMPLICATIONS OF THE BLINA OIL DISCOVERY
Authors: Playford Phillip E.
Published: August 2017

Devonian reef complexes outcrop spectacularly along the northern margin of the Canning Basin, forming what is probably the best preserved Palaeozoic reef belt in the world. The reefs extend into the subsurface, where they have been prime objectives for oil exploration since the mid 1950s. Exploration was finally successful in 1981, when Home Oil discovered the Blina oilfield in an Upper Devonian reef complex. It is the first potentially commercial field to have been found in the Canning Basin.Blina 1 flowed oil at rates of up to 905 barrels per day from the reef complex and overlying Upper Devonian to Lower Carboniferous dolomite. Two successful step-out wells have now been drilled, and although reserves of the field are still uncertain, economic development seems likely.The Blina reef complex is of Famennian age, belonging to the Nullara Cycle of reef development, while the overlying productive dolomite is within the Famennian-Tournaisian Fairfield Group. The Famennian reef margin is clearly displayed on seismic sections, but an earlier cycle of reefs, the Givetian-Frasnian Pillara Cycle, is more difficult to detect. These older reefs may nevertheless have better overall prospects than those of the Famennian.Positive indications of oil associated with Devonian reefs have also been obtained in the Bonaparte Gulf Basin, where widespread showings have been reported from mineral-exploration boreholes in Famennian reefal carbonates and overlying Lower Carboniferous carbonates.Recent seismic results have disclosed possible reef anomalies in several permit areas. The prospects for making further reef-associated discoveries seem promising along the Blina trend and elsewhere in the Canning and Bonaparte Gulf Basins. Prospective Devonian reefs are also likely to occur in the offshore area skirting the Kimberley Block and possibly extending as far south as the Carnarvon Basin.
THE PETROLEUM TENEMENT MAP OF AUSTRALIA
Authors: Blumer J. M.
Published: August 2017

Changes in the petroleum tenement map of Australia over the past twenty years reflect a number of trends in the petroleum exploration industry over that period. Variations in the total area under permit, the number of permits and average size can be correlated with such factors as changes in the level of exploration activity and the development of a fuller understanding of Australian regional geology. Changes in the net Australian equity in exploration tenements also show distinct trends, which can be related to some of the above factors.The legislative framework under which exploration takes place in Australia is very different from that of many other countries, particularly with respect to ownership of mineral rights and methods of awarding exploration rights. Petroleum legislation varies widely between the states and this has affected the pattern of exploration within Australia.
THE AGE DISTRIBUTION OF PETROLEUM IN AUSTRALIA
Authors: Evans P. R.
Published: August 2017

Although significant reserves of petroleum have been located in relatively few Australian provinces, when the host rocks of all Australian discoveries are plotted against geological time, there are few systems which do not contain reserves. When geochemical indications are included, Australia has a capacity to yield hydrocarbons from rocks as old as the Middle Proterozoic. When reserves are considered in terms of tectonic events, mid-Carboniferous, Late Triassic, mid-Jurassic and Late Cretaceous-Cenozoic phases of deformation have been responsible for the bulk of the petroleum traps. The least understood of these phases, that in the Cenozoic, was quantitatively the most significant in that it largely controlled trap formation in the Gippsland, Surat, Otway, Cooper, Eromanga and Carnarvon Basins. Reservoirs are dominantly in siliciclastic rocks deposited in environments ranging from alluvial to shelfal marine. The climatic and tectonic histories of the continent have resulted in it being more gas-prone than world averages.
CURRENT AND FUTURE DEVELOPMENT OF THE SURAT/BOWEN BASINS
Authors: McCaul B.
Published: August 2017

The Surat/Bowen Basins could be called the cradle of Australia's petroleum development, having provided the first commercial production of both oil and gas. Whilst total volume remains relatively small, this is spread amongst a number of producer groups.Success ratios for gas have remained high in 1982. Further planned installations will add to the existing infrastructure base in the region and maintain the impetus of development. Other longer-term developments are being canvassed ranging from pipelines to market gas from the northern Bowen Basin area, to a pipeline connection of Cooper Basin gas to the Surat/Bowen system. The Surat/Bowen Basins continue to appeal to smaller independent explorers thanks to low exploration costs and the prospect of cash flow in a short to medium time frame. A free-enterprise market in the Brisbane area with buyers competing for supplies, plus a potential market in Gladstone, are added incentives offering prospects of alternative-fuel-related pricing.Some experiment with previously unused technologies has commenced including massive hydraulic fracture stimulation and new pipeline construction methods. Overall, the Surat/Bowen Basins should be able to supply the natural gas needs of southeastern Queensland and Gladstone for up to 20 years. To achieve this, continued high activity in projects of small to medium scale is required.
THE GEOCHEMISTRY OF SOME BIODEGRADED AUSTRALIAN OILS
Authors: Alexander Robert , Kagi Robert Ian , Woodhouse Garry Wayne , Volkman John K
Published: August 2017

Degradation of petroleum in reservoirs by microorganisms is a process which has affected the chemical composition of many Australian crude oils. Oils from the Carnarvon and Gippsland Basins are used as examples to illustrate how the various classes of hydrocarbons are depleted in sequential fashion during the biodegradation process. Depletion of normal and branched alkanes, which is evident from gas chromatography, indicates that a crude oil has been mildly biodegraded. More advanced levels of biodegradation can be assessed from biomarker data obtained using gas chromatography-mass spectrometry. As the biodegradation process progresses one observes a sequential loss of n-alkanes, branched alkanes, δC-16 bicyclic alkanes, steranes with biological configurations, and finally, hopanes are converted into 25-norhopanes.The chemical compositions of the Eaglehawk, Rankin, and Windalia crude oils from the Carnarvon Basin suggest that they all result from a complex series of episodes of accumulation and biodegradation in the reservoirs. By assessing the proportions of each of the classes of characteristic marker compounds, and using the established relationship between reservoir temperature (depth) and the stages of hydrocarbon alteration during biodegradation, the approximate burial depths of the reservoirs at the times of biodegradation have been inferred. Thus, where multiple accumulation and degradation episodes can be recognised, the accumulation history of the oil in a reservoir can be reconstructed.
THE NEW OFFSHORE PETROLEUM LEGISLATION
Authors: Starkey J. C.
Published: August 2017

The new offshore petroleum legislation gives effect to the revised arrangements agreed between the Commonwealth and the States for the administration of offshore petroleum mining. Commonwealth legislation only applies beyond the three mile territorial sea in areas adjacent to the States and the Northern Territory. State and Northern Territory complementary legislation applies in the territorial sea area. All offshore mining whether inside or outside the territorial sea will be conducted in accordance with a common mining code.The Commonwealth legislation establishes Joint Authorities for each adjacent area consisting of the Commonwealth Minister for National Development and Energy and the relevant State or Northern Territory Minister. The Joint Authorities decide important questions of title under the legislation, including the grant, renewal and transfer of exploration and production permits and safety issues. Decisions on matters within the responsibility of the Joint Authorities rest finally with the Commonwealth Minister ensuring that the Commonwealth exercises proper constitutional responsibilities. Day-to-day matters arising in the administration of the legislation continue to be the responsibility of the State and Northern Territory Ministers, as Designated Authorities under the legislation, and their Departments continue to supervise offshore operations. The existing arrangements for sharing of royalties between the Commonwealth and the States and the Northern Territory continue, both inside and outside the territorial sea area.In administering the new legislation, the Commonwealth and the States and the Northern Territory are working closely to develop efficient and effective practices and a uniform and consistent approach to administration. These activities of the Commonwealth, the States and the Northern Territory are discussed in the context of issues arising since preparation of the legislation and emerging trends.
FINANCIAL OPTIONS FOR POTENTIAL PRODUCERS
Authors: Ogg Terry , Weston Guy
Published: August 2017

The experience of the last ten years has forced the capital market to give priority to investments that are structured in such a way as to maintain their viability under a wide range of operating conditions. Critical attention is given to the long term price trend, the markets available for products, production rates, government intervention, potential for industrial disruption, the proximity to the technology frontier of key aspects of the development, the project model and the degree of confidence that can be attached to expectations concerning these critical factors.A major element of equity — in the sense of ability to absorb losses — is an essential part of the financial structure of any development project in Australia. This equity participation may range from direct participation in residual ownership of the project through the various forms of royalty or revenue sharing arrangements to long term off-take agreements.The debt element can be increased if satisfactory security can be arranged. The tougher the security requirements, however, the lower the flexibility of the equity participants. In structuring the debt element the critical decisions involve the mix between fixed and floating rate components plus the currency composition of the financing.Bankers and others concerned with the financing of capital projects are constantly seeking financial structures which will satisfy the requirements of the various parties involved. Thus there will be considerable development of the concepts of debt and equity in coming years. Government authorities, capital market participants and explorer/developers will have to liaise closely to ensure that beneficial advances are not choked off by excessive conservatism.
DEVELOPMENT OF THE NORTH RANKIN FIELD, NORTH WEST SHELF, AUSTRALIA
Authors: Agostini M.  David
Published: August 2017

The North Rankin gas field discovered in 1971, has been evaluated by a series of appraisal wells and refinement of this is underway through the use of a 3D seismic survey. Extensive production testing on two wells was used to establish reservoir fluid characteristics, inflow performance and to predict reservoir behaviour.The North Rankin 'A' platform has been constructed of a standard steel jacket design. Components of the structure were built in Japan, Singapore, Geraldton, Jervoise Bay and Adelaide. Provision exists for 34 wells to be drilled from the structure to exploit the southern end of the North Rankin field.Simultaneous drilling and producing activities are planned, requiring well survey and deviation control techniques that will provide a high level of confidence. Wells will be completed using 7 inch tubing, fire resistant christmas trees, and are designed to be produced at about 87 MMSCFD on a continuous basis. Process equipment on this platform is designed to handle 1200 MMSCFD and is intended primarily to dry the gas and condensate and to transfer gas and liquid to shore in a two phase 40 inch pipeline. The maintenance of offshore equipment is being planned to maximise the ratio between planned and unplanned work.The commencement of drilling activities is planned for mid 1983, with commissioning of process equipment occurring in the second quarter of 198 The North Rankin 'A' platform will initially supply the WA market at some 400 MMSCFD offshore gas rate, requiring 7 wells. The start of LNG exports is planned for April 1987. The intial gas for this will be derived from the North Rankin 'A' platform.