bluuebunny/crossref_metadata_2025 huggingface dataset:
ORIGIN OF GILMORE GAS AND OIL, ADAVALE BASIN, CENTRAL QUEENSLAND
Authors: Boreham C.J. , Boer R.A. de
Published: August 2017

Dry gas in the Gilmore Field of the Adavale Basin has been sourced from both wet gas associated with oil generation, together with methane from a deep, overmature source. The latter gas input is further characterised by a high nitrogen content co-generated with isotopically heavy methane and carbon dioxide. The eastern margin of the Lissoy Sandstone principal reservoir unit contains the higher content of overmature dry gas supporting reservoir compiirtmenmlisalion and a more favourable migration pathway to this region. The combination of a molecular and multi-element isotopic approach is an effective tool for the recognition of an overmature, dry gas source. This deep source represents a play concept that previously has been undervalued and may be more widespread within Australian sedimentary basins.The maturity level of the wet gas and associated oil are identical, having reached an equivalent vitrinite reflectance of 1.4−1.6 per cent. Modelling studies support the concept of local Devonian source rocks for the wet gas and oil. Reservoir filling from late stage, high maturity oil and gas generation and expulsion, was a result of reactivation of petroleum generation from Devonian source rocks during the Early Cretaceous. The large input of dry gas from a deeper and highly overmature source is a more recent event. This gas can fractionally displace condensable C2+ liquids already in the reservoir possibly allowing tertiary migration into younger reservoirs, or adjacent structures.Oil recovered from Gilmore-2 has been sourced from Devonian marine organic matter, deposited under mildly evaporitic, restricted marine conditions. The most likely source rocks in the Adavale Basin are the basal marine shale of the Log Creek Formation, algal shales at the top of the Lissoy Sandstone, and the Cooladdi Dolomite. Source-sensitive biomarkers and carbon isotope composition of the Gilmore-2 oil have much in common with other Devonian-sourced oils from the Bonaparte and Canning basins. The chemical link between western and eastern Australian Devonian oils may suggest diachronous development of source rocks over a wide extent. This implies that the source element of the Devonian Petroleum Supersystem may be present in other sedimentary basins.
TEMPERATURE CONTROLLED POROSITY/PERMEABILITY REDUCTION, FLUID MIGRATION, AND PETROLEUM EXPLORATION IN SEDIMENTARY BASINS
Authors: Bjorkum P.A. , Nadeau P.H.
Published: August 2017

Findings mainly from the Norwegian Continental Shelf indicate that at temperatures greater than approximately 60°C, internally sourced quartz cementation and diagenetic clay become important porosity and permeability reduction factors, respectively. Porosity loss due to quartz cementation in sandstones and siltstones proceeds mainly independent of effective stress or fluid pressure. Porosity loss rates approach those required to generate high fluid overpressures at approximately 120°C, which can result in hydrofracturing of the overlying low permeability shales. In thick low permeable sediment sequences, the probability of km scale vertical fluid migration increases. These thermally driven processes are capable of generating and sustaining fluid overpressure and facilitate fluid migration for up to tens of millions of years. Unlike mechanical compaction models, this model predicts that porosity loss and therefore fluid migration will continue despite the buildup of overpressure, even during periods of no sedimentation. In sealed compartments, fluid flow from more deeply buried high permeable lithologies will occur by hydrofracturing of overlying low permeable lithologies, preferentially along near vertical faults if present. When hydrofractures are induced from high permeable sediments, they will propagate vertically through overlying low permeable sediments, unless they enter lithologies with sufficient permeability and volume to bleed off the fracture fluid propagation pressure. Quantitative analysis of the mineral reactions causing porosity loss cannot only identify sediments in thermal zones which are expelling fluids, but also lithologies in thermal zones which are likely to receive those fluids, in addition to the timing and rates of fluid migration. The model has important applications for evaluating petroleum exploration risks and the potential for remigrated hydrocarbon plays both at basin scale and prospect level.
COUPLED MECHANICAL/FLUID FLOW MODELS OF TRAP INTEGRITY AND FAULT REACTIVATION: APPLICATION TO THE NORTH WEST SHELF OF AUSTRALIA
Authors: Upton P. , Baxter K. , O'Brien G.W.
Published: August 2017

In the Timor Sea, northwestern Australia, convergence of the Australian and Eurasian plates in the latest Miocene induced fault reactivation which resulted in significant rupture of seals and reduced trap integrity, resulting in the partial to complete loss of hydrocarbons from many traps. In addition, this margin-scale tectonism produced a major fluid flow event which involved the flowage of hot, saline brines up major faults and through the Mesozoic and Tertiary sequences.In an attempt to provide a better understanding of the process of fault reactivation and trap breach, a number of coupled mechanical/fluid flow models have been developed for the Vulcan Sub-basin. These models consider the effect of fault permeability and fluid overpressures on fluid migration and seal rupture in an extensional tectonic environment. Modelling has shown that rupture of the seal is more likely where an overpressured region at depth within the sub-basin leads to overpressuring beneath the seal. Models in which the seal permeability is a function of material failure result in transient failure along the whole length of the fault, with fluid flow being directed upward through the seal.In addition, two specific accumulations have been modelled using a purely mechanical approach, namely the commercial Jabiru oil field and the breached East Swan accumulation. Fault reactivation and volume strain in the Jabiru and East Swan accumulations under an imposed stress field predict volume increase, associated breaching of the seal, and the development of Hydrocarbon-Related Diagenetic Zones (HRDZs) which map zones of trap leakage. For the Jabiru field, modelling predicts that volume strain occurs at the southern tips of the major Mesozoic faults. In the East Swan region, trap breach is predicted to occur in the SW of the field for stress states where σ1, is oriented between 15°E and 45°E. Volume strain is greater for E/W and NE/SW extension than for N/S extension. Both models show good agreement with seismic mapping of HRDZs.
PROSPERITY OR EROSION THROUGH UNITISATION?
Authors: Slattery P.D.
Published: August 2017

An inefficiency which exists in the petroleum industry is that petroleum fields do not recognise permit or licence boundaries-norat the time they are granted do permits or licences recognise field boundaries. The result is that occasionally more than one joint venture has the right to drain a petroleum accumulation. The manner in which the various interested parties address such a situation can materially enhance or diminish the value of their respective interests.In highly prospective areas and particularly those close to State or national borders, such as the Timor Sea, there is an enhanced likelihood that joint venturers will face the task of overcoming the inconvenience of fields straddling permit and licence boundaries.Until recently unitisation experiences in Australia have been dominated by the on-shore multi-field units of the South Australian Cooper Basin and Southwest Queensland Cooper Basin.However, in relatively recent times in the Timor Sea the Bayu-Undan field has been identified as straddling ZOCA 91-12 and 91-13 and the Laminaria field is known to extend from AC/P8 into WA-260P. There is also a greater likelihood of boundary straddling to occur in the Cooper Basin when PEL's 5 and 6 covering the South Australian Cooper Basin are relinquished in 1999, due to the greater number and smaller area of new permits.This paper addresses issues which arise when a single field straddles a permit or licence boundary1. In particular: (i) in what circumstances may those parties with an interest in the field be required to unitise the field; (ii) how do unit parties derive legal title to petroleum recovered through operations in that part of the field not covered by their respective licence or permit; (iii) how are participation interests to be determined; (iv) what are the other principal issues to be addressed in a unitisation; and (v) what are the alternatives to unitisation.
ASSESSMENT—TRANSLATING THE FUTURE INTO NUMBERS
Authors: Bradshaw M.T. , Bradshaw J. , Weeden R.J. , Carter P. , Vries D.F.H. de
Published: August 2017

Geological risk assessment is a comprehensive method used to compare different exploration opportunities at the prospect and play scale. Though common place in the petroleum exploration industry for decades, the assessment method can be updated and made more powerful when integrated with recent advances in geological concepts and technology, such as petroleum systems, relational databases and Geographical Information Systems (GIS). Empirical analysis of field size distributions and discovery histories is another traditional method for estimating undiscovered hydrocarbon potential for sedimentary basins or particular play types rather than for individual prospects. New mathematical descriptions of natural populations are available to further refine this approach; and the natural population of hydrocarbon fields is now seen as the petroleum system, rather than the basin or play. A key development has been the realisation that the methods of risk assessment can be applied to other complex decision making situations including environmental and resource planning.
RESOURCE SHARING AND STRATEGIC ALLIANCES-REDUCTION OF OILFIELD COSTS THROUGH INNOVATIVE SUPPLY CHAIN MANAGEMENT
Authors: Schenk A.R.J.
Published: August 2017

Supply chain management is the relatively recently implemented concept of managing an integrated supply function from production of a product or service to its receipt by its ultimate end user.This management philosophy has revolutionised production and manufacturing industries throughout the world, and has brought about dramatic efficiency improvements, with similar effects upon reducing overall costs. Traditionally, this was an area that was considered of low priority, presenting little opportunity for value adding or innovation, and characterised by adversarial, uncompetitive management techniques.Similarly, in the oil and gas industry, especially in the North Sea and the Gulf of Mexico, extended supply chains have necessitated a re-evaluation of the mechanisms used not only for provision of the supply service, but in the relationship between the operator and the service provider. Most notable examples being the CRINE (Cost Reduction Initiative for the New Era) initiative in the United Kingdom and Chevron Corporation's (one of West Australian Petroleum's participants and also its technical advisor) CSQIP (Chevron Supplier Quality Improvement Process) methodology.This paper will concern itself therefore with the application of cutting edge Supply Chain Management techniques garnered from both the North Sea and the United States. Focussing specifically upon alliancing/partnering, resource sharing and outsourcing, upon West Australian Petroleum Pty Limited (WAPET) and its respective contractors.It will seek to show that through innovative use of current supply chain management tools, as well as imaginative 'out of the box' thinking by WAPET personnel and contractor personnel alike, significant cost reductions and performance improvements can be brought to bear on oilfield operating costs.
EFFECTS OF OIL AND DISPERSED-OIL ON MATURE MANGROVES IN FIELD TRIALS AT GLADSTONE
Authors: Duke N.C. , Burns K. A. , Ellison J.C. , Rupp R.J. , Dalhaus O.
Published: August 2017

In late 1996, oil and dispersed-oil treatments were released into six experimental plots of mature mangroves near Gladstone, Queensland. Local stands of mangroves are dominated by Rhizophora stylosa up to 10 m tall. Each plot enclosed approximately 20 trees in plots of approximately 40m2. The object of the experiment was to simulate a large oil spill flooding mangroves at high tide, and to ascertain the relative effects of treatments on sediments, trees and animals, and to monitor short term recovery over one year. The oil used was weathered Gippsland Light, a waxy crude oil. This was applied on its own and in combination with the dispersant, Corexit 9527, at the same dosage of 5L/m2. A large proportion, if not all, crustaceans in the mangrove plots died within two days of oiling. Trees died in some plots after 2−3 months. In this preliminary assessment, there was no simple reason why trees died in some plots and not in others. For example, the amount of hydrocarbon in sediments was not correlated with effect. However, there were indications of synergistically-related factors, including presence of dispersant, sediment porosity, the number of burrowing crabs, and the presence of the mud lobster, Thalassina squamifera. Furthermore, after one month, the treated plots were partially recolonised by leaf-eating crabs. We present a preliminary assessment of results and observations using current data on hydrocarbon levels in sediments, growth and canopy condition of mangrove trees, and the presence and quantity of leaf-eating crabs.
MODELLING THE DISPERSION OF PRODUCED WATER DISCHARGES
Authors: King B.A. , McAllister F.A.
Published: August 2017

The ability of two state-of-the-art dispersion models (MUDMAP and the OOC model) to predict the fate of produced formation water (PFW) discharged by offshore petroleum platforms was examined. This was achieved by comparing model predictions with measurements made in the field. The models predicted peak concentrations of tracer PFW constituents (benzene and toluene) to typically within a factor of 2 and location to within 200 metres of the field observations. The models showed that water currents actively transport PFW plumes. Therefore, plume position is largely governed by local tide and wind conditions. Alteration in current strength over the tidal cycle was also shown to cause significant variation in plume concentration. Further, tidal oscillation may cause discharged PFW to pass more than once through a given area ('second dosing'). Once validated, these models can be used to greatly improve estimation of the potential ecological impacts of PFW plumes. This is achieved by using these models to investigate the range of potential PFW dispersion patterns possible for a region around the platform. Collectively, these simulations provide measures of best case and worst case scenarios which can be used for understanding potential ecological impacts. Further, the models can readily estimate the influence of changing discharge practices, such as: altering pipe width and/or depth, improving oil reduction prior to release, increasing discharge volumes, etc. Such features are essential for decision support to platform managers in their efforts to minimise the environmental impacts of offshore platform operations.
NETWORK INDUSTRY REGULATION AND CONVERGENCE IN SERVICE DELIVERY: CHALLENGES FOR SUPPLIERS, USERS AND REGULATORS
Authors: Asher A.
Published: August 2017

The Australian Competition and Consumer Commission (ACCC) has competition and fair-trading law responsibility for Australian industries. It has gained regulatory responsibilities for third-party access to telecommunications, soon will become the national regulator of gas pipeline access under a legislated code developed by the jurisdictions and industry working in a common forum, and will progressively become the national regulator of electricity transmission.This paper describes the ACCC's concept of the term 'efficient incentive regulation', gives examples of government decisions on network industry operations to which it is relevant and describes the general approach the ACCC will take in applying that concept, to encourage competition, innovation, economic investment and fair dealing by suppliers with users.The paper describes the relevance of the rise of national product markets and convergence in the delivery of telecommunications, electricity and gas services to the types of decisions the ACCC and State-based regulators will have to take and places those decisions in the context of common issues in regulatory reform internationally. Regulatory decisions taken for one network industry may have particular positive effects if the underlying principles flow on to others.A necessary part of dealing with national industries is the coordination of regulatory effort where Commonwealth and State/Territory regulators are involved. There is the risk in Australia that separation of regulatory powers between jurisdictional and national levels may cause welfare gains to business, customers and the wider community arising from the industry reform process to be lost if there are shortcomings in communications between regulators, duplication of effort or inconsistencies in approach. The paper describes the current division of responsibilities; the potential of the Utility Regulators' Forum to coordinate regulatory effort; and indicates the potential for losses of welfare and economic efficiency if COAG principles of a national approach to regulation are not fully embraced.The paper discusses the range of tools available to deal with challenges arising from privatisations, from the entry of multinational players to network industries and from the implementation of competition policy reforms, drawing on concerns about network industries raised with the ACCC, and on the ACCC's broader complaints experience. Finally, the paper outlines the reasons for policy-makers to pay particular attention to shaping and bringing light-handed but effective regulation to the areas of the converging network industries where market power remains unconstrained by competition, and for regulators to coordinate their administration of the regulated areas of network industries so that the policy objectives of incentive regulation are realised, resulting in the industry, users and the community sharing in the benefits.
PETROLEUM AND HOT DRY ROCK: TWO TYPES OF ENERGY SHARING COMMONALITIES
Authors: Narayan S.P. , Naseby D. , Yang Z. , Rahman S.S.
Published: August 2017

The Cooper Basin is the largest gas-producing basin in Australia and hosts a huge volume of natural gas in low permeability (known as 'tight gas') sandstone formations. Hydraulic fracture treatments, based on 'opening mode' fracture mechanics, are routinely carried out to unlock tight gas and to accelerate its recovery. Information regarding insitu stresses and natural fractures is required for successful fracture treatments. However, hydraulic fracturing is still often problematic, in part due to the relatively high insitu stresses and temperatures in the region. A vast amount of Hot Dry Rock (HDR) geothermal energy resources exists in granites below the sedimentary rocks in the Cooper Basin. Exploitation of HDR requires the same drilling and completion technologies as used in the petroleum industry. Hydraulic fracturing is also necessary for HDR reservoir creation, and requires characterisation of insitu stresses and natural fractures, as does tight gas production. It has been realised that the mechanism for reservoir stimulation in granitic rocks is proppant free shear dilation that is related to 'sliding mode' fracture mechanics. Furthermore, seismic imaging of hydraulic fracture propagation is well established in the HDR industry. These two technologies, developed in HDR, may have potential application to the petroleum industry for tight gas production. The geographic proximity of tight gas and HDR geothermal energy in the Cooper Basin and common exploitation technologies should justify close collaboration between the petroleum industry and HDR researchers.
COMMUNITY CONSULTATION IN DEVELOPMENT PROJECTS
Authors: Mathieson W.E. , Winters T.A.
Published: August 2017

The management of community consultation is a critical step in achieving timely Government approval for projects and laying the foundation for sound long-term relationships between local communities and project developers. The benefits of good relationships with local communities will flow on to Government support for the project, employee relations, service from local suppliers, and supportive neighbours. Both Government and project proponents are increasingly recognising the value of public participation in the environmental assessment of projects-it makes good business sense.The Queensland Government guidelines state that an appropriate public participation program is essential to the full conduct of the impact assessment (Department of Family, Youth and Community Care). This paper considers the issues involved in developing an appropriate community consultation program and looks specifically at the program adopted by BHP for the assessment of a proposed ammonium nitrate plant near Moura in Central Queensland. The BHP program was commended by the Department of Family, Youth and Community Care as a best practise example for other similar industrial projects.There is, however, community consultation and community consultation. The ammonium nitrate project was near a town which had suffered serious population decline and associated loss of services and infrastructure standards over the last decade. The town had also recently experienced major trauma as a result of the Moura underground mine tragedy in 1994.The social environment was in marked contrast to the environment of other projects which BHP had recently been involved in, such as the Minerva gas development project near Port Campbell in Victoria. Where the major focus of Minerva community consultation had been to address community concern about the environmental effects of the project and the impact of industrial development on the inherent lifestyle values of the area; the Moura community consultation program focussed on direct impacts on immediate neighbours and water resources, while the broader community debate was about employment opportunity, rebuilding the resources of the local community, and what can we do to make sure this project goes ahead?Whether the community supports industrial development or otherwise, community consultation is still an essential element of project planning. The issues will vary enormously from community to community-the focus will not always be on green issues. The key is to listen generously to the community and respond in a manner that genuinely recognises and addresses its particular issues.
MARGIN-SCALE, BASEMENT-INVOLVED COMPARTMENTALISATION OF AUSTRALIA'S NORTH WEST SHELF: A PRIMARY CONTROL ON BASIN-SCALE RIFT, DEPOSITION AL AND REACTIVATION HISTORIES
Authors: O'Brien G.W. , Morse M. , Wilson D. , Quaife P. , Colwell J. , Higgins R. , Foster C.B.
Published: August 2017

Australia's North West Shelf is segmented into four discrete margin-scale compartments which have distinct rift and reactivation histories. Two of the margin segments, the Carnarvon and Bonaparte compartments, are very wide (500–600 km), marginal plateau systems, whereas the other two segments, the Canning and Browse compartments, are narrower and steeper. The boundaries between individual rift compartments appear to be controlled by Proterozoic fracture systems.The Browse-Bonaparte transition zone is a major, northwest-trending Proterozoic fracture system which has a series of igneous intrusions along its length. These intrusions are located where the fracture system is cut by younger, northeast-trending extensional faults. This transition zone is a margin-scale fault relay zone, with intense fault overlap along the transition resulting in the zone being a long-lived, syn-rift high. Moreover, the transition zones between adjacent wide and narrow margins are prime locations for the entry point of siliciclastics into the rift or post-rift margin system. As a result, well-developed channel systems often cut through these boundaries and high quality reservoirs (particularly low-stand fans) are developed.Neogene fault reactivation, associated with convergence of the Australasian and Eurasian plates, is evident along the North West Shelf. The style of this reactivation is, however, closely controlled by the margin- scale architecture. In the Browse and Carnarvon basins, Neogene inversion is common, but at the leading edge of the collisional system, the Bonaparte compartment, the fault style is exclusively extensional. It appears that lithospheric flexure, associated with localised foreland development (i.e. the Timor Trough), has been the driving mechanism for the extensional faulting within the Bonaparte compartment. Crustal convergence seems to have been accommodated completely by thrusting on the northwestern margin of Timor and by foreland formation. In contrast, the Browse and Carnarvon compartments lacked a 'buffering' foreland system and, being adjacent to rigid and thin oceanic crust which transmits stress well over long distances, the inversional stresses were transmitted directly into these compartments.As a result of these margin-scale processes, the Bonaparte compartment is characterised by a thin regional seal (often 100 ms) on Neogene extensional faults—a combination which strongly favours fault seal failure and trap breach. In contrast, the Browse compartment is characterised by thick seals and small displacement Neogene faults, and thus the probability of fault seal failure is much less.
THE M. AUSTRALIS SANDSTONES, DAMPIER SUB-BASIN, AUSTRALIA
Authors: Crowley A.J.
Published: August 2017

Three independent Barremian sandstone units that are characterised by the M. australis palynozone have been identified in the Lewis Trough and Enderby Terrace of the southeastern Dampier Sub-Basin, offshore Western Australia. They constitute a basin-floor fan unit and shelfal transgressive unit that are characterised by the lower Af. australis sub-zone, a shelfal marine to fluvial unit that is characterised by the middle M. australis sub- zone and a shelfal marine unit that is characterised by the upper M. australis sub-zone. The M. australis sandstones are characterised by their excellent reservoir quality, generally common to abundant glauconite content and common provenance.Core, wireline log and seismic data from wells in the Lewis Trough indicate the sediments characterised by the lower M. australis sub-zone form a mass-flow deposit on the regionally extensive Intra-Muderong Hiatus. Transgressive shelfal greensands, interpreted to lie within the latter part of the lower M. australis sub-zone overlie the In tra-Muderong Hiatus on the Enderby Terrace. The glauconitic sandstones characterised by the middle M. australis sub-zone were deposited during a relative highstand and overlie a maximum flooding surface identified in wells on the southern Enderby Terrace. These deposits form the reservoir section for the Wandoo and Stag oil fields. At Wandoo they form a series of seismically definable progrades, whereas at Stag they are the distal toe-sets that lie sub-parallel to the underlying surface. The subsequent sequence boundary is identified in wells and on seismic data as an erosional surface cutting the underlying sediments. Glauconite-rich, transgressive deposits form a fining-up sequence overlie the sequence boundary. Glauconitic sandstones characterised by the upper M. australis sub-zone were deposited at the palaeo- shelf break during a minor regression.
WA-27I-P, EXMOUTH SUB-BASIN—INTEGRATED PROSPECTIVITY EVALUATION
Authors: Polomka S.M. , Bruins J. , Spanninga G.A. , Mennie I.P.
Published: August 2017

Permit WA-271-P in the southern Exmouth Sub-basin was initially gazetted as W96–20 in the 1996 gazettal round.It was recognised at an early stage that fluids found in Novara-1 (14° API oil), Pyrenees-1 and Macedon-1 (19° API oil and gas) made economic viability of traditional Barrow Group prospects in WA-271-P problematic and dependant upon the accurate prediction of reservoir development and fluid type.After award, Woodside embarked upon an intensive data acquisition program that included 800 km2 3D, 1,600 km 2D seismic, and 34,000 line km of aeromagnetic data. The integration of this data was completed in the latter part of 1998. The evaluation of the exploration 3D survey in the north eastern portion of the permit included volume interpretation and 3D visualisation, the results of which were integrated with an aeromagnetic and gravity study of the permit. The resultant interpretation clearly defined fault patterns and confidently identified and distinguished seismic anomalies caused by fluid effects from those generated by igneous bodies. This interpretation was supported by the application of quantitative interpretation techniques to Near, Full, Far stacks and DMO gathers with the knowledge then extrapolated to the regional 2D seismic grid beyond the 3D survey area.Environmental risk awareness and contingency planning formed an integral part of the early work within the permit. A metocean survey and spill modelling study were conducted leading to the production of a Resource Atlas. The results of the environmental studies were incorporated into the timing of exploration activities to minimise any potential impact on the environment.In summary, a focussed and multidisciplinary approach to the evaluation of the prospectivity of the permit was achieved through an integrated work flow. This has resulted in an attractive portfolio of prospects and leads from a number of play fairways, improved risk assessment, and the development of new plays within the permit, including both the traditional Barrow Group plays, and Jurassic and Triassic deep water plays. This approach has added considerable value to the permit by introducing new technologies and successfully managing risk with old play types.The first prospect drilled in the permit in December 1998, Vincent–1, was an oil and gas discovery.
REDUCING RESOURCE UNCERTAINTY USING SEISMIC AMPLITUDE ANALYSIS ON THE SOUTHERN RANKIN TREND, NORTHWEST AUSTRALIA
Authors: Sibley D. , Herkenhoff F. , Criddle D. , McLerie M.
Published: August 2017

Between 1973 and 1996 West Australian Petroleum Pty Limited (WAPET) discovered five major gas fields on the southern Rankin Trend including Spar, West Tryal Rocks, Gorgon, Chrysaor, and Dionysus (collectively termed the Greater Gorgon Resource). Recent discoveries at Chrysaor and Dionysus emphasise the role of subtle 3D seismic attributes in finding hydrocarbons and defining reserves with a minimum number of wells.The Gorgon, Chrysaor, and Dionysus fields were covered by 3D seismic data shot in 1991 and 1995, which led WAPET to discover Chrysaor and later Dionysus. Subsequent to the 3D acquisitions, field reservoirs have been correlated with anomalous seismic events (seismic amplitude and amplitude versus offset) that conform to depth structure. Follow-up work has shown that combining these 3D seismic attributes improves the prediction of wet sands, gas sands, and other lithologies.The resulting understanding and confidence provided by this 3D seismic has driven an aggressive exploration program and defined field reserves at a high confidence level. Results include the recent award of permit area WA-267-P to WAPET and the ongoing studies to begin development of the Greater Gorgon Resource.
GEOCHEMICAL CHARACTERISTICS OF AUSTRALIA'S SOUTHERN MARGIN PETROLEUM SYSTEMS
Authors: Edwards D.S. , Struckmeyer H.I.M. , Bradshaw M.T. , Skinner J.E.
Published: August 2017

The hydrocarbons discovered to date on the southern margin of Australia have been assigned to the Austral Petroleum Supersystem based on the age of their source rocks and common tectonic history. Modelling of the source facies distribution within this supersystem using tectonic, climatic and geographic history of the southern margin basins, suggests the presence of a variety of source rocks deposited in saline playa lakes, fluvial, lacustrine, deltaic and anoxic marine environments.Testing of the palaeogeographic model using geochemical characteristics of liquid hydrocarbons confirms the three-fold subdivision (Al, A2 and A3) of the Austral Petroleum Supersystem.Bass Basin oils are assigned to the Austral 3, Eastern View Petroleum System. The presence of oleanane in the biomarker assemblages of these oils, together with their negatively sloping, heavy, isotopic profiles, indicate derivation from Upper Cretaceous-Tertiary fluvio–deltaic source facies.In the eastern Otway Basin, oils of the Austral 2, Eumeralla Petroleum System are sourced by Lower Cretaceous (Aptian–Albian) coaly facies. Oil shows reservoired in the Wigunda Formation at Greenly-1 in the Duntroon Basin are possibly sourced from the Borda Formation and are assigned to the Austral 2, Borda Petroleum System.In the western Otway, Duntroon and Bight basins, a lack of definitive oil-source rock correlations precludes the identification of individual Austral 1 petroleum systems.
UPPER PERMIAN CARBONATE RESERVOIRS OF THE NORTH WEST SHELF AND NORTHERN PERTH BASIN, AUSTRALIA
Authors: Gorter J.D. , Davies J.M.
Published: August 2017

The Perth, Carnarvon, Browse, and Bonaparte basins contain Permian shallowmarine carbonates. Interbedded with clastic oil and gas reservoirs in the northern Perth Basin (Wagina Formation), and gas reservoirs in the Bonaparte Basin (Cape Hay and Tern formations), these carbonates also have the potential to contain significant hydrocarbon reservoirs. Limestone porosity may be related to the primary depositional fabric, or secondary processes such as dolomitisation, karstification, and fracturing. However, in the Upper Permian interval of the North West Shelf and northern Perth Basin, where there are no indications of significant preserved primary porosity in the limestones, all known permeable zones are associated with secondary porosity. Fractured Permian carbonates have the greatest reservoir potential in the Timor Sea. Tests of fractured Pearce Formation limestones in Kelp Deep–1 produced significant quantities of gas, and a test of fractured Dombey Formation limestone in Osprey–1 flowed significant quantities of water and associated gas. Minor fracture porosity was associated with gas shows in dolomitic limestones in Fennel–1 in the Carnarvon Basin, and fractures enhance the reservoir in the Woodada Field in the northern Perth Basin. Karst formation at sub-aerial unconformities can lead to the development of secondary porosity and caverns, as in the Carnarvon Basin around Dillson–1. Minor karst is also developed at the top Dombey Formation unconformity surface in the Timor Sea region.
NEW THINKING ON THE PETROLEUM PROSPECTIVITY OF DEEP MESOZOIC SEDIMENTS IN NEW ZEALAND BASINS
Authors: Cook R.A. , Gregg R.C. , Bennett D.J.
Published: August 2017

Geochemical studies, reinterpretation of early seismic data and information from new seismic surveys are extending the concept of economic basement for hydrocarbons in several New Zealand basins. Older Cretaceous and even Jurassic and Triassic rocks, previously considered to be 'basement' by petroleum explorationists, may have significance as petroleum prospects.Triassic–Jurassic Murihiku Supergroup sedimentary sequences are up to 15 km thick, and the upper parts are still of low metamorphic rank. Vitrinite reflectances and Hydrogen Indexes from Murihiku Supergroup coals sampled from outcrop and drillholes indicate good oil potential, and, together with rock porosity of up to 18%, suggest that the Murihiku Supergroup may be prospective.In the offshore Canterbury Basin, reinterpretation of seismic data has shown there is probably a thick sedimentary section below what was previously mapped as the regional basement horizon. This seismic interval can be related to a similar section developed in the adjacent Great South Basin where a mid-Cretaceous, rift- fill section of hydrocarbon-bearing rocks, drilled in the Kawau–1 well had good source and reservoir potential.In the onshore Canterbury Basin, a recent vibroseis survey has revealed apparent sedimentary section extending down to more than 4,000 m which might also be the expression of a mid-Cretaceous rift-fill section, similar to that in the nearby Great South Basin and in the formerly adjacent Taranaki Basin, or possibly the older Murihiku Supergroup. This potential for a mature oil and gas source section provides the basis for further exploration of the area.There are similar prospective sequences in several other New Zealand basins.
AGE DETERMINATION OF CRUDE OILS IN THE BARROW SUB- BASIN USING PALAEOCLIMATE RELATED VARIATIONS IN HIGHER PLANT BIOMARKERS
Authors: Aarssen B.G.K. van , Bastow T.P. , R  , Alexander  , Kagi R.I.
Published: August 2017

Variations in higher-plant-derived biomarkers in sedimentary sequences reflect changes in the palaeoclimatic conditions at the time of deposition. It is thought that changes in climate affect the distribution of higher plant populations growing on the hinterland, thus changing the contribution of these plants into the sediments. These variations can be measured using the abundances of three aromatic hydrocarbons: retene, cadalene and iP-iHMN. This was done for a Jurassic sedimentary sequence from the Koolinda–1 well in the Barrow Sub-basin, The obtained profile was related to an absolute time-scale. Measurement of the higher-plant-derived biomarkers in crude oils from the Barrow Sub-basin enabled accurate measurement of the age of their source rocks by using the Koolinda–1 profile as a reference. Most of these oils correlate with the Jurassic W. spectabilis dinoflagellate zone in the Oxfordian. Within this zone the oils fall into four age groups, reflecting four oil-prone intervals each separated by approximately 0.2 My. The oils that have been generated from each group can be found in specific reservoirs in the sub-basin, showing a pattern of migration away from the depocentre with decreasing age of the source rock. This method of determining the source rock age of crude oils enables detailed oil-source rock correlations. On a basin-wide scale it can provide insight into the location of major source rocks and migration pathways.
THE USE OF OIL FINGERPRINTING TO ENHANCE FIELD PRODUCTION ON BARROW ISLAND
Authors: Pitchford A. , Teerman S.C. , Clark P.A.
Published: August 2017

Oil production from well B28 completed in the Windalia Sand Reservoir of the Barrow Island Field was anomalously high in comparison to surrounding wells. Reservoir properties evaluated from the well could not account for the high production rates. Oil fingerprinting, which is a reservoir-geochemistry technique based on the gas chromatographic character of oil, was applied to identify the reservoir affiliation of the additional oil. The oil fingerprinting indicated that the oil from the B28 well is geochemically similar to oil from the deeper Flacourt Formation Reservoir.The results of the oil fingerprinting prompted a re-evaluation of the existing geological model in the area of well B28. The well intersects the Barrow Fault within a downthrown sliver of Windalia Sand. A large volume fracture stimulation over this interval may have opened the Barrow Fault to the underlying upper Flacourt Formation Reservoir. However, the structure outlined by the oil-water contact in the upper Flacourt Formation Reservoir had been mapped as a four-way dip closure 500 m north east of the B28 well. A review of the local stratigraphy identified a thin sand (the B28 sand), at the top of the Lowendal member of the IYluderong Shale, which could form a conduit from the Barrow Fault to the nearby upper Flacourt Formation Reservoir. The interpretation of the B28 sand conduit also increased the mapped extent of the upper Flacourt accumulation. In December 1997, 41 years after development began on Barrow Island, the B28 sand was successfully targeted by infill well CUM and subsequently developed as an extension to the Flacourt accumulation. Well CUM has the second highest initial production rate (1,360 BOPD) in the history of the field. The application of oil fingerprinting has enhanced the stratigraphic and structural model of an area with limited well control and sparse, poor quality seismic.
THE INTERPRETATION OF AEROMAGNETIC SURVEYS FOR HYDROCARBON EXPLORATION
Authors: Kivior I. , Boyd D.
Published: August 2017

Aeromagnetic surveys have been generally regarded in petroleum exploration as a reconnaissance tool for major structures. They were used commonly in the early stages of exploration to delineate the shape and depth of the sedimentary basin by detecting the strong magnetic contrast between the sediments and the underlying metamorphic basement. Recent developments in the application of computer technology to the study of the earth's magnetic field have significantly extended the scope of aeromagnetic surveys as a tool in the exploration for hydrocarbons. In this paper the two principal methods used in the analysis and interpretation of aeromagnetic data over sedimentary basins are: 1) energy spectral analysis applied to gridded data; and, 2) automatic curve matching applied to profile data. It is important to establish the magnetic character of sedimentary and basement rocks, and to determine the regional magnetic character of the area by applying energy spectral analysis. Application of automatic curve matching to profile data can provide results from the sedimentary section and deeper parts of a basin. High quality magnetic data from an experimental aeromagnetic survey flown over part of the Eromanga/Cooper Basin has recently been interpreted using this new approach. From this survey it is possible to detect major structures such as highs and troughs in the weakly magnetic basement, as well as pick out faults, and magnetic layers in the sedimentary section. The results are consistent with interpretation from seismic and demonstrate that aeromagnetic data can be used to assist seismic interpretation, for example to interpolate between widely spaced seismic lines and sometimes to locate structures which can not be detected from seismic surveys. This new approach to the interpretation of aeromagnetic data can provide a complementary tool for hydrocarbon exploration, which is ideal for logistically difficult terrain and environmentally sensitive areas.
3D STOCHASTIC RESERVOIR MODELLING AND FIELD DEVELOPMENT PLANNING
Authors: Jian F.X.
Published: August 2017

3D stochastic reservoir modelling is an emerging new technology for the oil and gas industry and is increasingly used by oil and gas companies as a tool to support major business decisions in field development planning, and the acquisition and management of petroleum assets. However, the potential benefit that 3D stochastic reservoir modelling can offer is still overlooked by many asset teams. Conventional methods are often still applied for field development planning and reserve estimation, where over-simplified geological models are used and reservoir uncertainties are substantially under-estimated. This is one reason why the oil and gas industry does not have a good track record in estimating reserves and field development planning.3D stochastic reservoir modelling methods that incorporate the structural-stratigraphic framework, facies and petrophyscial properties can ensure that the reservoir models fully describe reservoir heterogeneity. This in turn lays a sound foundation for field development planning. The 3D stochastic reservoir modelling methods also quantify and reduce uncertainties in various aspects of the reservoir. This allows a field development plan to be more robust yet flexible enough to take the advantage of upside reserve potential and to be economically sound if the downside case occurs. Based on quantification of uncertainties, optimal well positions and well paths can be designed to maximise oil and gas recovery.
DESIGN AND PLANNING OF LOW PERMEABILITY RESERVOIR STIMULATION BY ACID TREATMENT: AN INTEGRATED LABORATORY ANALYSIS
Authors: Azizi T. , Rahman M.M. , Rahman S.S.
Published: August 2017

The matrix reactivity of sandstone formations with mixtures of hydrofluoric (HF) and hydrochloric (HC1) acids has been studied experimentally using natural cores. A systematic approach, which includes laboratory analysis and computer modelling, has been used to design and plan acid treatment for sandstone formations. Matrix reactivity to acid mixtures (reaction rate) and the relationship between the porosity and permeability are established by subjecting the Pacoota Sandstone core samples to different acid concentrations and injection rates at different temperatures. Based on material balance and reaction kinetics a numerical simulator has been developed and verified in the laboratory. This simulator can adequately predict spent-acid concentration and changes in porosity and permeability as a function of acid penetration depth for given acid treatment conditions (acid concentrations, injection rates and treatment temperatures).
THE MEREENIE LEASE NEGOTIATIONS IN THE AMADEUS BASIN-AN HISTORICAL PERSPECTIVE
Authors: Liddle R.
Published: August 2017

Following the discovery of oil and gas, the Mereenie Joint Venture (MJV) applied for a production lease in November 1973. However, the Aboriginal Land Rights Act NT 1976 came into operation in January 1977 and the MJV was thereby required to negotiate with the Central Land Council in order to be granted the lease. The CLC was reluctant to proceed with negotiations because of the difficulty of identifying traditional owners. After 22 communications with the Council, the MJV grew impatient and the Northern Territory Government advised them to engage the author to assist in expediting the negotiations. After an intense period from March to November 1979 in which the traditional owners were identified and some violent exchanges occurred, agreement was reached on the financial terms. The Mereenie lease, which was the first petroleum lease on Aboriginal land, was granted on 18 November 1981. At present oil is piped to Brewer Estate in Alice Springs and then transported by rail to Port Stanvac in South Australia. Gas is transported to the Channel Island Power Station near Darwin via a 1,485 km pipeline. Aboriginal traditional owners receive royalty payments from all petroleum produced from Mereenie, in addition to sharing a 10% statutory royalty under the NT petroleum ordinance. The Mereenie agreement stands as a precursor to all agreements on Aboriginal land in central Australia.
ENVIRONMENTAL MANAGEMENT ON THE NORTH WEST SHELF: A REVIEW OF EXISTING DATA
Authors: Sherwood C.R. , Heyward A.J. , Revill A.T. , Scott L. , Fandry C.B.
Published: August 2017

The Western Australia Department of Environmental Protection initiated the North West Shelf Marine Environmental Management Study in recognition of development pressures on the complex and poorly understood marine environment of the North West Shelf. The four-year study, which began in 1998, is providing strategic information for long-term sustainable use and conservation management in the region. It will develop and consolidate the technical information base, scientific understanding, and predictive capabilities required to support an integrated, ecologically based management framework. As a first step in the study, we have reviewed scientific knowledge relevant to the marine environment of the North West Shelf and its management. With the cooperation of industry, academia and government, we have compiled a bibliography of more than 1,700 published and unpublished sources of data, models and hypotheses. Australian Petroleum Production and Exploration Association Ltd (APPEA) members are responsible for much of this information. In addition, we have critically assessed models and tools for environmental management and identified key gaps in current scientific understanding related to management of marine resources on the North West Shelf. Finally, we have highlighted opportunities for future research on the North West Shelf and provided the foundation for design of the study.