bluuebunny/crossref_metadata_2025 huggingface dataset:
THE HYDROCARBON POTENTIAL OF THE DUNTROON BASIN
Authors: Smith M. A. , Donaldson I. F.
Published: August 2017

An integrated evaluation of the Duntroon Basin has resulted in the identification of a new petroleum system. Petroleum system components are described in context of the basin-forming passive margin processes, the influence of pre-existing basement controls, and extra-basinal regional tectonic events. An understanding of the controls on the petroleum system components has provided a model for further exploration.Significant post-rift sequence boundaries are correlated with periodic adjustments in continental spreading rate and azimuth. The implications of these correlations implies that, at least in part, many of the sequences are tectonically controlled.The evolution of a rift basin neck to the southeast is interpreted to have partially controlled source rock development and reservoir quality through provenance variation in the Early Cretaceous. Synrift lower coastal plain coals and claystones of the Upper Borda Formation deposited in a restricted rift basin segment, are the principal source rock interval in the basin. Timing of hydrocarbon generation and migration for higher potential play fairways is favourable for the entrapment of hydrocarbons in the numerous earlier formed structures. Porosity/depth relationships are excellent and predictive sandstone depositional facies and provenance related porosity/depth trends are demonstrable.Geochemical analysis of oil shows at Greenly-1 demonstrates the existence of at least two types of migrated oil; one with a distinct terrestrial character and the other a mixed source. Analysis of a Greenly-1 RFT gas sample indicates the existence of migrated thermal gas.
STRUCTURAL EVOLUTION OF THE CARNARVON TERRACE, WESTERN AUSTRALIA
Authors: Baillie P.W. , Jacobson E.
Published: August 2017

The under-explored Carnarvon Terrace is situated offshore of the Cape Range area in the Carnarvon Basin near the boundary of the Gascoyne and Exmouth Sub-basins. The stratigraphy of the area is controlled by only two wells (Pendock-1, Yardie East-1), but several onshore wells aid interpretation of seismic data.Understanding of the structural evolution of the region is facilitated by interpretation of a high-resolution non-exclusive seismic survey acquired by Geco-Prakla in 1993 (GPCTR-93 Survey).Three major tectonic stages are responsible for the structural configuration of the region:Late Palaeozoic extension in the Gascoyne Sub-basin;continental break-up between Australia and Greater India which took place along a major fracture marked by the Flinders-Long Island-Learmonth fault system active in Late Triassic and Early Jurassic times; andthe collision between Australia and Asia that commenced in Miocene times and is continuing to the present day. This event, marked by wrench and compressional structures, and often reactivation of older structures, is one of the most economically important in Australian geological history.From a regional prospectivity viewpoint at least three plays are worthy of further investigation.
DEPOSITIONAL HISTORY OF THE SOUTHERN TAROOM TROUGH, QUEENSLAND
Authors: Beeston J.W. , Dixon O. , Green P.M.
Published: August 2017

The Permian succession in the southern Taroom Trough is generally believed to be the source of hydrocarbons in the Roma Shelf oil and gas fields and the Moonie oil field. The succession is characterised by complex relationships between marine and fluvio-deltaic facies which reflect marked differences in the depositional history of the Trough.On the basis of transgressive events, the succession has been subdivided into four sedimentary cycles, the boundaries of which do not always correspond to formation boundaries or seismic horizons. Notably, the top coal in any area forms a prominent seismic reflector, but coals in individual areas can be demonstrated to occur at different stratigraphic positions relative to the major interval of coal development. These higher coals reflect changing depositional settings with time.Palaeogeographic reconstructions demonstrate a complex depositional history of sediment input onto a shallow shelf from differing directions and with different rates of input.
THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN
Authors: Luxton C.W. , Horan S. T. , Pickavance D.L. , Durham. M.S.
Published: August 2017

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.
MESOZOIC TECTONICS OF THE OTWAY BASIN REGION: THE LEGACY OF GONDWANA AND THE ACTVE PACIFIC MARGIN—A REVIEW AND ONGOING RESEARCH
Authors: Hill K.A. , Finlayson D.M. , Hill K.C. , Cooper G.T.
Published: August 2017

Mesozoic extension along Australia's southern margin and the evolution and architecture of the Otway Basin were probably controlled by three factors: 1) changes in global plate movements driven by mantle processes; 2) the structural grain of Palaeozoic basement; and, 3) changes in subduction along Gondwana's Pacific margin. Major plate realignments controlled the Jurassic onset of rifting, the mid-Cretaceous break-up and the Eocene onset of rapid spreading in the Southern Ocean.The initial southern margin rift site was influenced by the northern limit of Pacific margin (extensional) Jurassic dolerites and the rifting may have terminated dolerite emplacement. Changed conditions of Pacific margin subduction (e.g. ridge subduction) in the Aptian may have placed the Australia-Antarctic plates into minor compression, abating Neocomian southern margin rifting. It also produced vast amounts of volcanolithic sediment from the Pacific margin arc that was funnelled down the rift graben, causing additional regional subsidence due to loading. Albian orogenic collapse of the Pacific margin, related to collision with the Phoenix Plate, influenced mid-Cretaceous breakup propagating south of Tasmania and into the Tasman Sea.Major offsets of the spreading axis during breakup, at the Tasman and Spencer Fracture zones, were most likely controlled by the location of Palaeozoic terrane boundaries. The Tasman Fracture System was reactivated during break-up, with considerable uplift and denudation of the Bass failed rift to the east, which controlled Otway Basin facies distribution. Palaeozoic structures also had a significant effect in determining the half graben orientations within a general N-S extensional regime during early Cretaceous rifting. The late Cretaceous second stage of rifting, seaward of the Tartwaup, Timboon and Sorell fault zones, left a stable failed rift margin to the north, but the attenuated lithosphere of the Otway-Sorell microplate to the south records repeated extension that led to continental separation and may be part of an Antarctic upper plate.
CHEMOSTRATIGRAPHY AND THE COMPOSITION OF OILS IN THE PERTH BASIN, WESTERN AUSTRALIA
Authors: Summons R. E. , Boreham C. J. , Foster C. B. , Murray A. P. , Gorter J. D.
Published: August 2017

The known global secular change in the distribu­tion of carbon isotopes between the Palaeozoic and Mesozoic is the basis of a new oil-source correlation tool. The carbon isotopic signatures of n-alkanes, in combination with information about the distribu­tions of diagnostic biomarkers have been used to classify Perth Basin oils according to the age of the source. These data confirm that most of the oil in the northern Perth Basin originates from the basal section of the Kockatea Shale.Oils exclusively from Triassic sources are isotopically light with n-alkane 813C values near −34%o PDB. Jurassic oil from Gage Roads-1 is isotopically heavy (~24%o) and is also distinctive in its relatively high content of conifer-derived aromatic hydrocar­bons. Condensates from Jurassic source intervals in the Dandaragan Trough are isotopically heteroge­neous with n-alkane 813C values between −25%o and −29%o. The Whicher Range-1 condensate, of appar­ent Permian origin, is isotopically heavy with n-alkane 5l3C values near −25%o. The isotopic data provide information about variation in sedimen­tary facies and possible multiple sources that is not evident from the biomarker signatures. All the Jurassic oils have significant amounts of bicadinanes, resin-derived biomarkers until recently attributed exclusively to tropical angiosperms.A strong excursion in the isotopic signature of organic carbon is present in core at 2,293 m in the Woodada-2 borehole and occurs with no obvious lithological change. Similar isotope shifts are known to mark the Permian-Triassic boundary globally and have been previously recognised in the Bonaparte, Bowen, Canning, Carnarvon and tenta­tively in the southern Perth basins. The excursion in Woodada-2 is abrupt and suggests a significant time break in sedimentation. However, diagnostic Permian palynoflora or fauna have not been de­tected below 2,293 m in the Woodada-2 core, and hence, the assignment of a Permian-Triassic con­tact cannot be made unequivocally with the exist­ing data.
A REVIEW: ORGANIC GEOCHEMICAL STUDIES BY LASER PYROLYSIS MASS–SPECTROMETRY AND HOW THEY COMPARE WITH FLASH PYROLYSIS MASS–SPECTROMETRY STUDIES
Authors: Greenwood P. F. , Sherwood N.
Published: August 2017

Various methods of laser pyrolysis have been used by researchers to investigate at a molecular level the chemistry of dispersed organic matter. An understanding of molecular composition is important for evaluations of oil generation potential and maturation levels of source rocks. Laser-based pyrolysis-mass spectrometry studies as applied to petroleum source rocks and coals are reviewed. Experiments undertaken to date involve three main techniques: (i) laser ionisation-mass spectrometry; (ii) laser pyrolysis-gas chromatography-mass spectrometry; and (iii) laser desorption-electron im-pact-mass spectrometry. These techniques have had variable degrees of success for detecting structurally significant hydrocarbon products. Typically assessed through comparison with conventional flash pyrolysis data, the relative merits of the different techniques are described.The most powerful analysis is obtained through the combined use of chromatographic separation and mass spectrometry. The emergence of the laser pyrolysis-gas chromatography-mass spectrometry technique offers enormous potential for various geochemical applications. Laser pyrolysis in conjunction with a microscope (micropyrolysis) allows analysis of specific organic entities, thereby avoiding the masking of individual properties through bulk analysis. However, laser micropyrolysis-gas chromatography-mass spectrometry has not been widely accepted because of the complexities inherent in interfacing the required hardware devices and the high cost of laser instruments compared with conventional pyrolysers. Chromatography also adds cost with regard to both instrumentation and analysis time. Unfortunately, the ability of laser ionisation to provide insights into molecular structure is severely limited by a predominance of carbon cluster ions from highly carbonaceous materials.In contrast, the laser desorption-electron impact ionisation routine yields large ion concentrations of aliphatic and aromatic products. Sufficient information has been obtained with this method to distinguish source rocks and coals of different organic composition.
ADDING VALUE FROM A TAXATION PERSPECTIVE
Authors: Capito A.
Published: August 2017

Adherence to 'best practice' methodologies requires all corporations to review the structure of, and resources devoted towards, their tax function. A number of observations in respect of best practice initiatives in the tax function arena are detailed.
COMPARATIVE FUNDING CONSEQUENCES OF LARGE VERSUS SMALL GAS-FIRED POWER GENERATION UNITS
Authors: Johnson N.G.
Published: August 2017

Gas producers are increasingly looking to privately-owned gas-fired power generation as a major growth market to support the development of new fields being discovered across Australia.Gas-fired generating technology is more environmentally friendly than coal-fired power stations, has lower unit capital costs and has higher efficiency levels. With the recent downward trends in gas prices for power generation (especially in Western Australia) it is likely that gas will indeed be the consistently preferred fuel for generation in Australia.Gas producers should be sensitive to the different financial and risk characteristics of the potential markets represented by large versus small gas-fired private power stations. These differences are exaggerated by the much sharper focus given by the private sector to quantifying risk and to its allocation to the parties best able to manage it.The significant commercial differences between classes of generation projects result in gas producers themselves being exposed to diverging risk profiles through their gas supply contracts with generating companies. Selling gas to larger generation units results in gas suppliers accepting proportionately (i.e. not just pro-rata to the larger installed capacity) higher levels of financial risk. Risk arises from the higher probability of a project not being completed, from the increased size of penalty payments associated with non-delivery of gas and from the rising level of competition from competing gas suppliers.A conclusion is that gas producers must fully understand the economics and risks of their potential electricity customers. Full financial analysis will materially help the gas supplier in subsequent commercial gas contract negotiations.
THE NEW ZEALAND PETROLEUM INDUSTRY'S EXPERIENCE UNDER THE RESOURCE MANAGEMENT ACT
Authors: Crawford D.
Published: August 2017

There has been recent interest shown by Australian State and Federal Ministers in New Zealand's Resource Management Act. 'What does this Act require of industry? where did it come from? what does it do and how much support does it have?', are the main questions asked by these Ministers. It appears that some Ministers in Australia may want to copy parts of the Act. The main thrusts of the legislation, its disadvantages and suggestions for improvements are discussed.The main points are summarised:Prior to 1991 the management and planning of resources and the environment within New Zealand was controlled by a myriad of Acts. In 1991 the Government repealed 54 pieces of legislation and replaced these with the Resource Management Act (RMA) and the Crown Minerals Act (CMA). These two pieces of legislation have had an enormous impact on petroleum exploration.Prior to 1991 the Town and Country Planning Act was the main Act responsible for providing guidance for planning processes with a focus of managing activities, whereas the focus of the RMA is the sustainable management of the effects of activities on natural and physical resources (land, water and air). The RMA provides that the harvesting of minerals is exempt from the sustainability requirement, but that the effects of exploration and mining activities on the environment are not.Industry is supportive of the approach that effects are to be managed, not the activities themselves, as it places all activities on a level playing field.There are some disadvantages of the RMA. If parts of the Act are to be copied by other countries, then it would be wise to avoid these.
THE ENFORCEABILITY OF TYPICAL JOA DEFAULT PROVISIONS
Authors: Slattery P.D. , Radford G.
Published: August 2017

Courts will not always give effect to the terms of JOA default provisions which require forfeiture of a defaulting party's joint venture interest. However, given the nature of resource joint ventures, the circumstances in which relief against forfeiture will be granted are rare.Forfeiture of a joint venture interest will not be enforced if it is penal in nature. Typical JOA forfeiture clauses are unlikely to be penal in nature as their primary object is to facilitate the continuation of the joint venture project.If two or more alternative and inconsistent remedies are available to non-defaulting joint venturers, they must elect which remedy they wish to pursue. We do not believe typical JOA default remedies present inconsistencies which require an election.In recent years, Australian courts have demonstrated a willingness to imply terms of reasonableness into contracts to avoid a harsh or unjust outcome. We do not expect this trend to affect typical JOA default clauses.
OIL SPILL PREPAREDNESS: THE OIL INDUSTRY AND THE NATIONAL ARRANGEMENTS
Authors: Blackmore D.J.
Published: August 2017

It is vital that there is a credible and well organised arrangement to deal with oil spills in Australia.The National Plan to Combat Pollution of the Sea by Oil, the umbrella oil spill response plan for Australia, is a combined effort by the Commonwealth and State Governments, the oil industry and the shipping industry.The Australian Marine Oil Spill Centre (AMOSC), formed in 1991, is an industry centre set up for rapid response with equipment and resources, together with a training and industry coordination role.A review of the National Plan in 1992, identified, amongst a number of issues, that the National Plan needed to be re-focussed, to ensure full integration of all government and industry activities for the first time. This has led to greatly improved understanding between government and industry and significant improvements to Australia's oil spill response preparedness. The National Plan review has also resulted in a clearer definition of the responsibilities for operational control, together with the organisational structure to deliver a successful response.The current state of Australia's National Plan is such that it does provide confidence that there is the capacity to deliver an effective response to oil spills in the marine environment. Nevertheless, there is more to be done, particularly in the areas of planning and exercises.
THE DEVELOPMENT OF A FRACTURED RESERVOIR MODEL FOR THE PALM VALLEY GAS FIELD
Authors: Berry M.D. , Stearns D.W. , Friedman M
Published: August 2017

A fractured reservoir model has been developed for the Palm Valley gas field, located WSW of Alice Springs, in the Amadeus Basin, NT. Definition of this complex, naturally fractured, Ordovician gas reservoir has required an integrated approach involving multiple studies to develop the geological model that has formed the basis for reservoir simulation and the rationale for the location of new wells. In addition, new seismic data provided fundamental input to the structure/fracture model of the field. Results suggest a primary, northsouth compression for the origin of structures in the basin and that Palm Valley resulted from a single, balanced folding phase. The seismic data show that Palm Valley is not an arcuate anticline as previously mapped, but is an elongate WSW to ENE trending, doubly plunging anticline with an offset crest and minor reverse faults at reservoir level. Investigations have shown that the majority of fractures in the reservoir outcrop are extremely ordered and there is definite structural control of the fracture spacing in the brittle reservoir rocks. Fracture trajectory and fracture intensity maps have been constructed, the latter providing the mechanism for distribution of fracture parameters around the field. The orientation of fractures measured at depth in the reservoir match exactly the fractures predicted from the structure/fracture model. This is the first time a fractured reservoir model that has been developed for Palm Valley, and it will form the basis for the further study and future development of the field.
PETROLEUM SYSTEMS OF THE PETREL SUB-BASIN-AN INTEGRATED APPROACH TO BASIN ANALYSIS AND IDENTIFICATION OF HYDROCARBON EXPLORATION OPPORTUNITIES
Authors: McConachie B.A. , Bradshaw M.T. , Bradshaw J.
Published: August 2017

A petroleum system evaluation of the Petrel Sub-basin in the Bonaparte Gulf, northwest Australia, suggests that the wells drilled in the area have not fully evaluated the petroleum potential. Some of the lowest risk plays in the basin have not been tested adequately or have not been assessed in probable economic fairways.Several important discoveries have highlighted the existence of at least three petroleum systems in the Petrel Sub-basin; Larapintine, Transitional and Gondwanan. Best known are the Gondwanan gas discoveries at Petrel, Tern and most recently Fishburn, where hydrocarbons are reservoired in Late Permian sandstones and are probably sourced from Permian deltaic sequences. Kurt her inshore, oil has been recovered from Carboniferous and Early Permian reservoirs at Turtle and Barnett. The source of the oil is considered to be Carboniferous anoxic marine shales of a distinct petroleum system transitional between the Gondwanan and Larapintine systems (Milligans Formation source rock and Late Carboniferous to Permian reservoirs). Onshore, there is a gas discovery at Gariinala-1 and significant oil shows in Ningbing-1, in Late Devonian Larapintine system rocks. Geochemical analysis of the oil shows it to be sourced from a carbonate marine source rock, different from the clastic derived oils obtained from Turtle and Barnett.Recent discoveries in the Timor Sea have provoked a re-assessment of the very similar, largely untested, Mesozoic, Westralian petroleum system in the outer part of the Petrel Sub-basin. The prospective Mesozoic play fairway occurs in the northern part of the Petrel Sub-basin, extending into Area B of the Zone of Cooperation.
A SEQUENCE STRATIGRAPHIC STUDY OF THE CALLOVIAN FLUVIO-DELTAIC TO MARINE SUCCESSION WITHIN THE ZOCA REGION
Authors: Arditto P.A.
Published: August 2017

This paper presents the results and conclusions of an integrated sequence stratigraphic study of the Callovian marine succession across area 'A' of the Zone of Cooperation (ZOCA). This study utilised wireline log and conventional core data from within ZOCA 91–1 and ZOCA 91–12, and incorporated trade data from adjacent permits, to generate a rational depositional model for the succession. Three distinct third-order sequences have been recognised from the detailed correlation of regional flooding surfaces recognised on wireline log motifs calibrated against conventional core and biostratigraphy. The base of the oldest third-order sequence includes section previously referred to as Plover Formation, and roughly corresponds to the W.digitata/W.indotata zone boundary. The Callovian Unconformity within the ZOCA region is thus relegated to a third-order sequence boundary or disconformity. The term Elang Formation is proposed for this Callovian succession which comprises three third-order sequences mappable across ZOCA. The well-type section for the Elang Formation is Elang-1, and an additional well reference section would be Elang-2, as both these wells contain significant and complementary cored section.Detailed sedimentological studies on conventional core reveal that the Elang Formation comprises a succession of coastal plain to nearshore marine sediments, ranging from low sinuosity fluvial channel, fluvial-dominated deltaic, proximal low sinuosity estuarine channel and distal outer bay sediments. Only minor wave-dominated, open marine shoref ace intervals were interpreted, most of the cored intervals indicating a fluvially-domi-nated shoreline with minimal wave reworking. Isopach and per cent sand maps generated for each third-order sequence comprising the Elang Formation illustrate the successive sediment distribution patterns across ZOCA during the progressive marine transgression from the top of the fluvio-deltaic Plover Formation to the base of the offshore marine Lower Flamingo Group. The sand-trend maps for the three sequences which comprise the Elang Formation indicate a fluvial/estuarine-dominated delta system, sourced from the region of the Laminaria Field, AC/P8, building east and southeast out across the ZOCA region. A modern analogue of this delta system in both size and sedimentation style may be the Brahmaputra/Ganges Delta of East Bengal.
PETROLEUM POTENTIAL OF THE ERINGA TROUGH IN SA AND THE NT
Authors: Alexander E.M. , Pegum D. , Tingate P. , Staples C.J. , Michaelsen B.H. , McKirdy D.M.
Published: August 2017

The Eringa Trough occupies an area of over 8,000 km2 in SA and the NT and contains an estimated 1,500 m of Permo-Carboniferous and over 1,000 m of Mesozoic sediments. Early Permian depositional history of this frontier region is similar to that of the Cooper Basin in northeastern SA. The Eringa Trough has limited seismic coverage and sparse petroleum and mineral exploration drillholes are located on the trough margins. Interpretation of 255 km of new seismic and reprocessed data has delineated a number of undrilled prospects.Excellent quality reservoirs are present. Early mature to mature, Permian and Jurassic source rocks occur, including good to excellent Type-II kerogens within an equivalent of the Jurassic Birkhead Formation. Apatite fission track analysis of Permian and Jurassic sediment shows palaeo-temperatures were approximately 30-40°C higher than at present and that cooling occurred within the last 60 Ma. This suggests that Permian and Jurassic sediments in the deeper parts of the Eringa Trough have experienced temperatures suitable for petroleum generation.An integrated evaluation of the Eringa Trough in SA and the NT has resulted in a greater understanding of this frontier area which has the potential for significant commercial petroleum discoveries.
THE DEVELOPMENT AND REGIONAL SIGNIFICANCE OF RIFT-RELATED DEPOSITIONAL SYSTEMS IN THE DAMPIER SUB-BASIN
Authors: Miller L.R. , Smith S.A.
Published: August 2017

The influence of tectonic control is more apparent than eustatic control on the rift-related stratigraphy of the Dampier Sub-basin. The correlation of observed depositional events to causative processes and global events is problematic due to the use of alternative geological time scales, causing ambiguity and uncertainty. The Harland (1989) time scale with a revised palynological allocation, combined with genetic sequence stratigraphy, and Prosser's concept of the tectonic systems tract, has proved useful during evaluation of the stratigraphy of the Dampier Sub-basin.Palaeo-topography was a major factor in sediment distribution and facies architecture of rift-related strata in the Dampier Sub-basin. This must be considered when assessing the stratigraphic trapping potential for hydrocarbons. There is a close association between the styles of depositional systems observed in the Dampier Sub-basin and stage of rifting and basin development. Five tectonic systems tracts, each with unique depositional systems have been identified and described; pre-rift, rift initiation, rift climax, immediate post-rift and late post-rift tectonic systems tracts.The use of a single time scale has enhanced the relationship between tectonic systems tracts (super-cycles) and the timing of depositional events recorded during previous genetic stratigraphic studies in the North West Shelf. The tectonic nature of super-cycle scale events should be temporally and spatially assessed in detail before the effects of eustatic change are evaluated for rift-related successions of the North West Shelf. The problem can be further exacerbated when the absolute error of chronological dating exceed the temporal frequency of eustacy, causing tenuous correlations of depositional events to a global eustatic curve.
THE ORIGIN OF BARROW SUB-BASIN CRUDE OILS: A GEOCHEMICAL CORRELATION USING LAND-PLANT BIOMARKERS
Authors: van Aarssen B. G. K. , Alexander R. , Kagi R.I.
Published: August 2017

New biomarker technology has been developed to provide insight into the age range of the source rocks of crude oils and condensates from the Barrow Sub-basin. These methods are based on a biomarker or chemical fossil fingerprint provided by the land-plants that were present at the time of deposition of the source rocks. The changing distribution of plants through time, in response to factors such as climate change, provides a time-based fingerprint that can be compared with that from the crude oil. The plant fingerprint was established using samples from the Koolinda-1 exploration well which range in age from Middle to Upper Jurassic. The distributions of the key marker compounds were measured in a suite of 25 crude oils and condensates. Sixteen of the crude oils that were analysed in this study correlated closely with Koolinda-1 sediments from a narrow Oxfordian age-range, more precisely the W. spectabilis dinoflagellate zone. The observed correlation suggests that these oils were generated from time-equivalent source rocks. Four oils correlated well with slightly older sediments. Their relatively high values for the total higher plant input suggest that their source rocks were closer to their respective supplies of plant material than the Koolinda-1 sediments. Five condensates did not fit the higher plant fingerprint of the Jurassic in Koolinda-1. These oils might have been generated from source rocks older than those analysed at Koolinda-1.
AN EARLY CRETACEOUS SOURCE ROCK IN THE KENDREW TERRACE, DAMPIER SUB-BASIN?
Authors: Ryan-Grigor S. , Griffiths C. M.
Published: August 2017

The Early to Middle Cretaceous is characterised worldwide by widespread distribution of dark shales with high gamma ray readings and high organic contents defined as dark coloured mudrocks having the sedimentary, palaeoecological and geochemical characteristics associated with deposition under oxygen-deficient or oxygen-free bottom waters. Factors that contributed to the formation of the Early to Middle Cretaceous 'hot shales' are: rising sea-level, a warm equable climate which promoted water stratification, and large scale palaeogeographic features that restrict free water mixing. In the northern North Sea, the main source rock is the Late Jurassic to Early Cretaceous Kimmeridge Clay/Draupne Formation 'hot shale' which occurs within the Viking Graben, a large fault-bounded graben, in a marine environment with restricted bottom circulation and often anaerobic conditions. Opening of the basin during a major trans-gressive event resulted in flushing, and deposition of normal open marine shales above the 'hot shales'. The Late Callovian to Berriasian sediments in the Dampier Sub-basin are considered to have been deposited in restricted marine conditions below a stratified water column, in a deep narrow bay. Late Jurassic to Early Cretaceous marine sequences that have been cored on the North West Shelf are generally of moderate quality, compared to the high quality source rocks of the northern North Sea, but it should be noted that the cores are from wells on structural highs. The 'hot shales' are not very organic-rich in the northern Dampier Sub-basin and are not yet within the oil window, however seismic data show a possible reduction in velocity to the southwest in the Kendrew Terrace, suggesting that further south in the basin the shales may be within the oil window and may also be richer in organic content. In this case, they may be productive source rocks, analogous to the main source rock of the North Sea.
RISK ALLOCATION IN PETROLEUM JOINT VENTURES
Authors: Barrymore S.J.
Published: August 2017

This paper will consider aspects of contractual risk allocation in the energy industry.The industry is a mature one, with sophisticated and experienced contractors and operators. Hydrocarbons have uniquely hazardous characteristics making all parties, the State and the community acutely aware of the need to control the means of its discovery, appraisal, production and transportation.The Exxon Valdez and Piper Alpha disasters are paradigm examples of the drastic consequences and the magnitude of the risk, that can flow from what might otherwise be considered 'a minor act or omission'.Risk management is based on the premise that it is in the interest of any project that certain risks be borne by certain parties, normally the person in the best position to control the risk concerned. A realistic approach to allocation of risk will reduce costs and claims and prevent over or under insurance. Where a risk which can be efficiently absorbed or covered by one party is passed to another, the short-term gain may be more than offset by the other party's increased charges or defensive practices for absorbing the risk or its inability to perform following a liability arising from that risk.As noted above, the risk allocation and management technique dealt with in this paper is contractual. Parties seek to distribute and allocate risks by the use of clauses of indemnity, limitation, exclusion, insurance and force majeure. Each of these contracts allocate risk to one party or the other for matters such as personal injury, property loss and damage, public liability, pollution, negligent workmanship and indirect loss or damage.This paper will examine the structure of these clauses (other than insurance) in the context of offshore development projects, centring around the joint operating agreement made between an operator and the licence holders, and a consideration of contracts entered into between the operator and its participants and the project contractors and project insurers. It will also address the issue of conduct in breach of statute and the effect of such conduct on indemnity and insurance agreements.
THE GOLDFIELDS GAS PIPELINE: 'OPENING A NEW FRONTIER'
Authors: Ride B.M.
Published: August 2017

Gas exploration and development in the northwest Pilbara in WA has increased due to the commitment of the Goldfields Gas Transmission Joint Venture to a 1,380 km gas pipeline linking the north west Pilbara to the east Pilbara iron ore region and the northern and central Goldfields. Construction of the GGT pipeline was approved in January 1995 and it is expected the pipeline will be servicing major mining operations in Newman, Mt Keith, Leinster and Kalgoorlie by August 1996. Other existing mining operations located near the pipeline are expected to convert from distillate for power station fuel to gas in 1996-97. Major new mining prospects in these highly prospective minerals provinces also offer potential for increased gas demand and GGT Pipeline throughput.The commercial arrangements for GGT Pipeline services are the first in Australia to be offered under the open access arrangements espoused by the Federal and WA Governments, and have set a benchmark for other pipelines in Australia. The innovative distance related pipeline tariff arrangements offer prospective gas shippers a simple method for evaluating use of the GGT pipeline and securing gas transmission services.The GGT Pipeline has had and will continue to have a major effect on the WA gas scene, stimulating gas exploration by capturing an established base load energy market currently dependent on liquid fuels and stimulating further WA gas demand growth.
A GEOPHYSICAL APPRAISAL OF THE EAST SPAR GAS/CONDENSATE FIELD
Authors: Craig A. , Sit H. , Sheridan P. , MacLean L.
Published: August 2017

III order to appraise and define the East Spar gas/ condensate field the YVA-214-P joint venture has employed various geophysical techniques. The East Spar field is a Top Barrow Group four-way-dip closure in depth, but has no closure in time, requiring accurate velocity interpretation for depth conversion. Evaluation of the field has followed an approach of 2D reprocessing followed by acquisition of a 3D survey. Appraisal techniques have included inversion to acoustic impedance, amplitude versus offset studies and amplitude mapping.Initially defined from regional well control, a velocity model was constructed from multi-vintage velocity data, then later refined from the 3D velocity data. The velocity model was constructed by careful interpretation of normal moveout velocities from seismic processing. The velocity field is affected by anomalous velocities in the shallow section and a slow velocity zone over the field possibly related to gas permeation throughout the sealA probabilistic approach was adopted for depth con version and reserves estimation. Minimum, most likely and maximum case depth maps were derived by perturb ing the velocity model away from well control. Alterna tive depth conversion techniques were employed with varying success to quantify the uncertainty and accuracy of the velocity model.The reservoir sand exhibits a discrete phase change. Such gas sands are notoriously difficult to identify, interpret and map. Slight changes in the reservoir and sealing unit quality affect the phase and amplitude response of the seismic data. Normal incidence seismic models were constructed to analyse the effects of variations in reservoir, seal and sand thickness on the seismic response. These models were used to constrain several attribute based net pay maps. The reserves estimates from these attribute based maps compared favourably with the highest confidence estimates derived from depth mapping.
FLEXURAL ISOSTATIC MODELLING AS A CONSTRAINT ON BASIN EVOLUTION, THE DEVELOPMENT OF SEDIMENT SYSTEMS AND PALAEO-HEAT FLOW: APPLICATION TO THE VULCAN SUB-BASIN, TIMOR SEA
Authors: Baxter K. , Cooper G. T. , O'Brien G. W. , Hill K. C. , Sturrock S.
Published: August 2017

Although the petroleum industry is commonly interested in the upper few kilometres of the lithosphere, it is the deeper stretching events which may drive the development of regional thermal perturbations and which may overprint a significant thermal signature onto the shallower section. The Vulcan Sub-basin, which is located in the Timor Sea, northwestern Australia, has undergone a period of rifting during the Late Jurassic and shows a classic transition from intra-continental rifting to passive margin subsidence during the Late Jurassic to Early Cretaceous. A model has been developed of the Late Jurassic rifting history of the basin, which includes the flexural and stratigraphic response, and the development of the Cretaceous to Recent post- rift basin history. Quantification of the associated vertical motion of the lithosphere suggests that the transition is related to increased ductile extension in the lower crust and lithospheric mantle with little attendant upper crustal faulting to record the magnitude of this event in the structural history of the Vulcan Sub-basin. This lack of upper crustal deformation has resulted in an under- appreciation of the importance of this extensional event.By modelling the Jurassic to Recent basin history, a thermal model may be built allowing predictions of palaeo-heat flow during the critical time of hydrocarbon generation. The model predicts that during the Jurassic and Early Cretaceous, increased lower crust and lithospheric mantle extension produced a thermal anomaly of ~20mW/m2 across the Vulcan Sub-basin. The relaxation of this thermal anomaly in the Cretaceous and Tertiary produced a rapid post-rift subsidence which allowed flooding of the margin, with increased subsidence towards the northwest. However, the evolution of this thermal perturbation beneath the upper crust resulted in a time lag between Late Jurassic rifting and maximum basin heat flow in the Early Cretaceous of up to 30 million years after Callovian breakup Therefore, the simple relationship between upper crustal faulting and total lithosphere stretching common in intra-continental rifts is predicted to break dow n immediately preceding conti nental breakup and necessitates modelling of the transition from syn-rift to post-rift stratigraphy in order to predict the thermal history of the Vulcan Sub-basin.
DEPOSITION AL AND DIAGENETIC CONTROLS ON THE QUALITY OF BARROW GROUP SANDSTONE RESERVOIRS, BARROW SUB-BASIN, NORTH WEST SHELF, WESTERN AUSTRALIA
Authors: Kraishan G. M. , Lemon N. M. , Tingate P.R.
Published: August 2017

The main controls on Barrow Group reservoir quality are depositional (lithofacies) and post depositional (di- agenetic). Barrow Group sediments were deposited in environments ranging from non-marine to deep marine. The upper sandstones (Flacourt Formation) in the centra] and southern parts of the sub-basin are dominantly of good reservoir quality, consisting mainly of marine- reworked strandplain and shoreface deposits. The lower sandstones (Malouet Formation), however, in the Barrow Sub-basin depocentre, are composed predominantly of slope apron deposits, consisting of tight, matrix-rich, non-productive sandstones. The Flag Sandstone, distributed along the northern part of the sub-basin, is made up mainly of mounded turbidite deposits consisting of excellent reservoir quality, coarse-grained sheet turbid-ites.Petrographic observations of theliarrow Group show that sands are, in general, extremely well sorted and display a unimodal grain-size distribution. Grain size varies slightly with the depositional environment; the mounded turbidite sandstones average 197 f.im (fine sand) and the slope apron sandstones average 185 pm (fine sand). The grain size in the marine-reworked strandplain sandstones averages 300 j.im (medium sandstones). Detrital depositional matrix, mechanical compaction and cementation are the main causes of poor reservoir quality. Mechanical compaction is responsible for destroying up to 60 per cent of the original porosity. Chemical compaction has had much less effect. Precipitation of authigenic minerals has reduced, on average, the primary intergranular porosity to 12 per cent of the whole rock-volume.In some cases, secondary porosity development has greatly enhanced the reservoir quality of the Barrow Sub-basin sandstones. It results from dissolution of calcite, dolomite and potassium feldspar. Reservoir quality is most improved along the margins of the sub-basin as this is where carbonate and feldspar were most abundant.
GAS DISPLACEMENT: AN IMPORTANT CONTROL ON OIL AND GAS DISTRIBUTION IN THE TIMOR SEA?
Authors: Lisle M. , O'Brien G. W. , Brincat M. P.
Published: August 2017

A study of gas fields in the Timor Sea has shown that these traps often contain palaeo-oil columns, with a high abundance of oil bearing fluid inclusions recorded in sands which are presently gas saturated. These palaeo- oil columns are substantial, suggesting the volume of liquid hydrocarbons that has been redistributed is significant. This remobilised oil in effect constitutes an oil charge of known volume for nearby structures, with seismic mapping confidently allowing the recognition of remigration fairways into up-dip traps. For example, at Oliver-1, a 115 m relict oil column, equating to original oil in place of over 166 MMBBL, has been identified. However, estimates of current oil in place account for less than 45 MMBBL, suggesting that more than 120 MMBBL of oil has been displaced across the spill point of the Oliver structure. Remigration of this oil can be mapped into an adjacent fault block, representing a new exploration play. Significantly, the likelihood of this untested trap containing liquids is supported by the presence of an oil leg at Oliver-1, which shows that only oil has been displaced from the Oliver trap.At Keeling-1, a smaller palaeo-oil accumulation has been detected which equates to about 14 MMBBL originally in place. However, the mechanisms responsible for the passage from palaeo-oil accumulation to the present gaseous hydrocarbon phase are often complex and decisions regarding a potential oil leg need be made judiciously. For example, at Keeling-1, oil shows and hydrocarbon related diagenesis in the overlying section provide compelling evidence that oil was lost due to fault breach rather than gas displacement.In contrast, a lack of evidence for palaeo-oil accumulation at Sunrise-1 and Troubadour-1 is also significant, as it removes the potential for an oil leg displaced either down-dip within the same structure or as a remigrated oil charge to adjacent up-dip structures. Significantly, these fields presently contain condensate and would have existed as separate oil and gas legs if charge occurred before dew point pressure was reached. The absence of a palaeo-oil column implies that the traps were charged after formation pressures exceeded the dew point of the reservoired gas. At Troubadoirr-1, this observation constrains the time of charge to the last 5-10 Ma, when pressures within the trap are estimated to have reached dew point.