bluuebunny/crossref_metadata_2025 huggingface dataset:
PETROLEUM GENERATION AND SOURCE ROCK ASSESSMENT IN TERRIGENOUS SEQUENCES: AN UPDATE
Authors: Powell T.G. , Boreham C.J.
Published: August 2017

Analytical pyrolysis and sealed tube pyrolysis at low temperatures have been used to study the timing and petroleum generating capacity of selected Permian through Tertiary coals and carbonaceous shales in relation to their petrographic and elemental composition. The results show that judicious application of flash pyrolysis techniques in conjunction with more conventional procedures are essential for effective source rock assessment in terrigenous source rocks, particularly in those of lower quality.Although the petroleum potential of the samples follows the broad trends in petrographic composition established for Australian coals, that is, relative proportions of vitrinite, inertinite and liptinite, there is much variation which cannot be explained petrographically at the maceral group level. Furthermore, there is no simple relationship between pyrolytic hydrocarbon yield from terrigenous kerogens and overall elemental composition. The yield and composition of pyrolysable normal hydrocarbons varies widely depending on the nature and amount of liptinite macerals, particularly for samples with Hydrogen Indices below 300. Liptinite-poor (Mass balance calculations based on Rock-Eval analyses of samples from the Jurassic Walloon Coal Measures show that the maximum oil formation occurs over a very narrow maturation window from 0.8 to 1.0 per cent Ro, although small amounts of oil may be generated at lower maturation levels. The gas to oil ratio of the generated hydrocarbons is constant up to a reflectance level of 1.0 per cent Ro, where upon the proportion of gas increases rapidly. The low quality Permian source rocks from the Cooper Basin have a lower ratio of labile to refractory kerogen than the Jurassic and Tertiary examples. As a result, the gas to oil ratio of hydrocarbons formed in the oil window is higher and the oil potential appears to be exhausted at an earlier stage of maturation. Efficient migration of hydrocarbons from Permian sediments in the Cooper Basin also appears to occur at a relatively early stage of maturation compared with the Jurassic Walloon Coal Measures.
WELL TUBULAR CORROSION IN THE COOPER/EROMANGA BASIN
Authors: Bishop Ian , Martucci Steve
Published: August 2017

In September 1987 the Della-1 gas well blew out at approximately 19.5m (64ft) abovesea level (42.7m (140 ft) KB) due to corrosion of the production casing and tubing.The production casing failure and other similar corrosion occurrences were considered to be due to sulphate-reducing bacteria which have been identified in a large number of wells in the Cooper Basin. It was considered possible that iron sulphide was being deposited on the casings in the surface-to-production casing annulus at the air/water interface promoting the formation of anodic sites and therefore corrosion.Further investigations of the evidence indicates that sulphate-reducing bacteria are not the major contributors to the corrosion as was initially believed. Field studies, laboratory analysis and ongoing well programs show that the process of differential aeration is the prime cause of the casing corrosion. Corrosion has been found to occur predominantly at a depth of between 18.3m (60 ft) and 36.6m (120 ft) above sea level and occurs over a band of 6.1 m (20 ft) to 9.1m (SO ft) in each well in conjunction with the external water table.As a result of this corrosion failure SANTOS has initiated a regular program of well maintenance, annulus inhibitor top-ups and pressure testing. A total of 315 wells have been tested to date, production casing corrosion problems have been identified in 35 wells, 31 wells have been repaired and four wells abandoned.
THE PAPUA NEW GUINEA STANDARD PETROLEUM AGREEMENT: ITS STRENGTHS AND WEAKNESSES
Authors: Grace John G. , Williamson Max
Published: August 2017

Until the discovery of the Iagifu/Hedinia/Agogo (now called Kutubu) Fields, Papua New Guinea (PNG) petroleum laws followed, in both legislation and administration, the Australian model brought to PNG by the former pre-independence administrators. In particular, exploration and production rights derived from licences issued under the national petroleum legislation.This practice was distinctly different from the State practice of PNG's near neighbours to the north, particularly Indonesia and Malaysia. In those countries rights to explore for and produce petroleum were acquired by entry into a production sharing contract with the State which to a considerable extent was a self-contained legal code.In addition, PNG has developed a unique contractual model which has been grafted on to the existing licensing system. This new model, embodied in a Standard Petroleum Agreement (SPA), incorporates elements of the negotiated petroleum agreements common in countries with a less developed legal system.The scope of this paper is to assess the strengths and weaknesses of the SPA, both internally and against the framework of the PNG legislation, particularly the Petroleum Act, as well as against the background of similar petroleum agreements offered to oil companies by other countries in the region.
RIVOLI-1 GAS DISCOVERY — EXMOUTH SUB-BASIN, WESTERN AUSTRALIA
Authors: Lawry Philip J. , Carter Paul A.
Published: August 2017

Offshore exploration in the Exmouth Gulf commenced with seismic surveys during the early 1960s and resulted in the first well Bundegi-1 being drilled in 1978. This well, situated on the Rivoli-Bundegi Trend, encountered an interpreted residual hydrocarbon zone in the Birdrong Sandstone, an 18 m untested hydrocarbon zone in the Learmonth Formation, and tight, possibly gas bearing sandstones in the Mungaroo Formation.Modern shallow-water marine seismic data acquired by the EP 325 Joint Venture during surveys in 1987 and 1988 allowed accurate mapping of the basal Cretaceous section and the distribution of the Birdrong Sandstone. Complex structuring in the Jurassic and Triassic section was also resolved with the modern data.The Rivoli gas discovery, approximately 4.5 km northeast of Bundegi-1, was made in August 1989, with the intersection of a 10.5 m hydrocarbon column consisting mainly of gas but with a very thin oil leg (0.2 m). The Birdrong Sandstone reservoir comprises 10 m of fluvial sandstones overlain by 7 m of marginal marine sandstones and provides an important calibration point for depositional environments in this unit. The Rivoli gas pool occurs in a simple, downthrown anticline sealed by Winning Group shales. Geochemical analysis of oil extracted from core, suggests an earlier charge of 'Rough Range-type' oil, possibly generated from pre-Jurassic source rocks.Several prospects and a variety of play types are recognised and considerable exploration potential remains to be tested along the Rivoli-Bundegi Trend.
DEVELOPMENT OPTIONS FOR OFFSHORE OIL AND GAS FIELDS: IMPLICATIONS FOR OPTIMUM LONG-TERM RECOVERY
Authors: Wright D.J. , Poidevin S.R. le
Published: August 2017

Technology used in the Australian offshore oil and gas industry in recent years has diversified with the introduction of innovative concepts for field developments. These innovations are aimed at cost reduction and greater access to reserves, especially those in small and remote fields. Further innovations are anticipated as research progresses in several areas of potential cost reduction. Changes in technology can dramatically affect the relative economics of data acquisition, contingency planning and the extent of field development. Drilling and workover economics, well servicing, reservoir surveillance and the opportunities for infrastructure development are strongly dependent on the choice of development technology. These choices, in turn, have implications for long-term recovery, including the discovery and development of new pools and extensions to known pools, overall field recovery factors, the opportunities for development of gas caps and nearby fields, and the future potential for enhanced oil recovery (EOR).Government involvement in development approvals in various countries has diverse objectives. The Australian Petroleum (Submerged Lands) Act specifies as one objective the optimum long-term recovery of petroleum. Critical areas of interest are pre-development planning with necessarily incomplete information, the phenomenon of unexpected reserves growth, and provision for contingencies such as well failures. Early drilling and completion decisions and infrastructure planning have major effects on future developments. Subjects of direct relevance for future improvements in development economics include reductions in pipeline construction costs, reductions in the cost of drilling from mobile rigs and flexibility in completion design.
SPECIAL INTEREST GROUPS IN THE ENERGY INDUSTRY — WHAT RIGHTS DO THEY HAVE?
Authors: Barrymore S.J.
Published: August 2017

There is a world-wide trend to increasing social involvement in development projects. This is certainly true in Australia where proponents of developments that impact on a community or affect the environment can expect to be subject to close scrutiny by both government and special interest groups and, occasionally, face militant opposition to their activities.In recent times the trend is for these differences to be resolved in the courts. While the action that BHP Petroleum took against Greenpeace is well known and represents something of a landmark in Australia, most of the court actions have related to urban land development. Consequently, a body of law has evolved — and will so continue — delineating the general principles to be applied in this area and determining where the balance lies between the resource developer and his detractors.This paper examines the rights of a special interest group to legitimately review and scrutinise proposals for oil exploration and development, and what recourse it has to the courts to ensure that the proper processes are followed. Conversely, the position of an oil explorer is also considered, in circumstances where a special interest group embarks on a program of interference or obstruction that is contrary to law. The oil explorer faces a difficult decision: either he can take up the cudgels himself and use the legal process to restrain the interference or seek the assistance of the Police and other government authorities.While the legal balance presently favours the oil explorers, there are indications, both in the courts and through legislative amendment, that this balance may be redressed and tilt back strongly in favour of special interest groups.
REGIONAL SIGNIFICANCE OF THE ARQUEBUS- I WELL, BROWSE BASIN, NORTH WEST SHELF, AUSTRALIA
Authors: Haston Roger B. , Farrelly John J.
Published: August 2017

The Arquebus-1 well was drilled in 1991 on exploration permit WA-206-P located in the southern portion of the Browse Basin. The Browse Basin is one of the least explored offshore basins in Australia and although two major gas discoveries have been made, no significant oil accumulations have been found. The Arquebus-1 well tested Middle to Upper Jurassic sandstones in a large three-way dip closed structure along the main Jurassic basin margin fault system, which has subsequently been inverted by Tertiary wrench faulting. The well was plugged and abandoned despite the presence of numerous shows and pay indicated by wireline logs. Five formation tests were performed and despite a long 12-hour test, only mud filtrate was recovered, suggesting that significant fluid invasion had occurred. The pressure data indicate a good water gradient with a 51 m gross column of light oil and gas. This is supported by detailed analysis of fluid inclusions, capillary pressure analysis, wireline logs and sidewall cores. The total gross hydrocarbon column may be as great as 105 m. The extremely low clay content, the uniform pore throat size, the slow drilling rate and the overbalanced drill mud made the sandstones prone to the nearly complete flushing of formation fluids and associated formation damage. The presence of an inferred oil column in the Jurassic sandstones at Arquebus-1, indicates that oil has been generated in the Browse Basin and that three-way dip closed structures are potentially viable traps in the area.
WELL-BORE INSTABILITY IN THE NORTH WEST SHELF OF AUSTRALIA
Authors: Tan C.P. , Willoughby D.R. , Hillis R.R. , Zhou S. , Mühlhaus H-B , Aoki T.
Published: August 2017

Well-bore instability, experienced mainly in shales, has resulted in significant drilling delays and abandonment of wells in the North West Shelf of Australia. Although these problems may be induced by physico-chemical interactions, there is an increasing awareness that instability in this region is principally associated with in situ stresses that are high relative to the strength of the materials.This paper describes the research undertaken by the Australian Petroleum Cooperative Research Centre to assist industry in understanding and managing stress-induced well-bore instability in this region. To conduct such stability analyses the basic information required includes knowledge of the orientation and magnitude of the principal in situ stresses and the strength and deformation response of the materials to stress changes imposed by drilling. The required data can be determined using welllogging, analytical and laboratory techniques.Analytical methods can be used to examine the relationship between well-bore stability and changes introduced through drilling. Spreadsheets based on the analytical methods have been produced and applied to the assessment of drilling alternatives and/or design of some well-bores in the North West Shelf.The application of the critical mud weight contour plots and mud weight stability profiles produced by the spreadsheets in assessing drilling alternatives, selection of optimum well-bore alignment and mud weight design are demonstrated through examples. The analyses showed that counter to intuitive expectations, an inclined well may be more stable than a vertical well depending on the well-bore direction, deviation angle and stress regime.
EVALUATION AND MANAGEMENT OF THIN OIL COLUMN RESERVOIRS IN AUSTRALIA
Authors: Irrgang H. R.
Published: August 2017

Thin oil columns represent a common and important class of hydrocarbon reserve which are notoriously difficult to evaluate and produce. This paper provides case studies of examples of these reservoirs in Australia and summarises the production methods, well performance and recovery efficiencies.Thin oil column reservoirs are defined here as reservoirs which will cone both water and gas when produced at commercial rates. The oil zone can have a pancake or rim geometry. Examples within Australia include Bream and Snapper (Gippsland Basin), South Pepper and Chervil (Carnarvon Basin), Chookoo (Eromanga Basin) and Taylor (Surat Basin).Parameters which are particularly important in defining the performance of these reservoirs are: horizontal and vertical permeability, column height, stratigraphie dip, well spacing, and oil viscosity. High horizontal permeability is more critical than in other reservoir types as it controls the effectiveness of gravitational forces in opposing coning and other unwanted flows by reducing pressure gradients. Low vertical permeability mitigates coning but can limit across strike drainage in dipping strata. Oil viscosity is also particularly important, even when the mobility ratio is favourable, as it controls the gas/oil ratio and water cut during coning.As coning (by definition) is inevitable the key production issue is gas cap management. The main options are:Limit gas coning by controlling completion depth and production rates.Allow gas cap shrinkage and 'chase' the oil column upwards via recompletions.Reinject gas to control gas-oil contact position.For the latter two options in particular, ultimate reserves are a strong function of the capacity of the installed production facilities, especially offshore, where fixed operating costs are high. When gas cap management is not compromised, reserves increase with higher total fluid withdrawal rates. Examples of the various gas cap management and production strategies are included.Both horizontal (South Pepper, Bream) and conventional (Chookoo, Taylor) completion techniques have been applied to thin oil column reservoirs in Australia. Horizontal completions can increase productivity, mitigate coning and increase the well drainage areas (particularly if drilled across dip in heterogeneous reservoirs). However, horizontal completions are particularly vulnerable to poor cement jobs, natural fractures and undesirable fluid contact movements.A variety of other completion techniques have been tried worldwide in thin oil columns with mixed success. These include multiple completions in the water, oil and/or gas to allow separate production, and injection of fluids to make permeability barriers or alter relative permeability.A number of scaling rules are included to assist in using offset field data for evaluation of thin oil column reservoirs. Improved understanding of these complex reservoirs will maximise their economic potential.
SWELLING BEHAVIOUR OF MIXED-LAYER CLAYS IN HYDROCARBON RESERVOIRS
Authors: Baker Julian C. , Uwins Philippa J.R. , Mackinnon Ian D.R.
Published: August 2017

The freshwater sensitivity of a variety of mixed-layer illite/smectite and chlorite/smectite clays has been studied with an Environmental Scanning Electron Microscope (ESEM) in order to determine whether all hydrocarbon reservoirs hosting these clays should be regarded as freshwater sensitive. Experimental procedures involved closely comparing in situ mixed-layer clay within selected areas at high magnification before and after prolonged freshwater treatments.The response of smectite-rich illite/smectite (two samples; 10–20 per cent illite interlayers) to freshwater immersion varied greatly. One sample rapidly swelled to many times its original volume to form a pervasive gel that greatly reduced porosity and permeability, whereas the other sample underwent only a subtle morphological change that had little or no adverse effect on reservoir quality. Illite-rich illite/smectite (three samples; 65—>85 per cent illite interlayers) and chlorite-rich chlorite/smectite (two samples; 50 per cent and >70 per cent chlorite interlayers) underwent no morphological change when immersed in freshwater for up to three months, indicating that these clays in sandstones are unlikely to cause formation damage due to swelling if exposed to freshwater-based fluids.
GIPPSLAND, A COMPOSITE BASIN-A CASE STUDY FROM THE OFFSHORE NORTHERN STRZELECKI TERRACE, GIPPSLAND BASIN, AUSTRALIA
Authors: Gilbert Michael B. , Hill Kathy A.
Published: August 2017

Detailed interpretation of reflection seismic and well data from the northern Strzelecki Terrace constrain the effect of Southern Margin and Tasman Sea rifting on the evolution of the Gippsland Basin. A new model is proposed which divides the basin into two structurally distinct provinces (East and West Gippsland Basin), separated by a broad zone of accommodation which is referred to in this paper as the 'Kingfish/Tuna Transition Zone'. This zone is a distinct region across which structural styles change within the basin due to the interaction of extensional forces resulting from both Southern Margin and Tasman Sea rifting. No evidence has been found, however, for the existence of transfer zones within the northern margin of Gippsland Basin as previously suggested by other authors.The Gippsland Basin is observed to have a composite history; a younger 'Tasman Rift' Basin (a Tasman Sea aulacogen) overlying a regionally more extensive 'Strzelecki Basin' (the result of rifting along Australia's Southern Margin). Both basins have formed as half graben with opposing asymmetry. Re-evaluation of the Cretaceous palynology in conjunction with reflection seismic data from selected wells have enabled division of the Cretaceous section of the northern Strzelecki Terrace into three tectonically distinct sedimentary units: the Lower Strzelecki, Upper Strzelecki and Golden Beach Megasequences. The Lower Strzelecki Megasequence exhibits considerable thickening towards a south-bounding master fault, and is inferred to have been deposited during a phase of active rifting. It is separated from the overlying Upper Strzelecki Megasequence by a pronounced late Aptian age angular unconformity. The Upper Strzelecki Megasequence is a thick sedimentary unit which shows less syn-sedimentary faulting and is inferred to be deposited during a period of tectonic quiescence, possibly during a sag phase following active rifting. The Golden Beach Megasequence shows renewal of rifting with growth towards a north bounding fault system and is differentiated from the underlying Strzelecki Megasequences by a distinct change in seismic character across a subtle early Campanian age angular unconformity.
SEQUENCE STRATIGRAPHY AND THE DEPOSITIONAL HISTORY OF THE MURTA MEMBER (UPPER HOORAY SANDSTONE), SOUTHEASTERN EROMANGA BASIN, AUSTRALIA: IMPLICATIONS FOR THE DEVELOPMENT OF SOURCE AND RESERVOIR FACIES
Authors: Gorter John D.
Published: August 2017

The Hooray Sandstone (Namur Sandstone Member and overlying Murta Member) was deposited during the Early Cretaceous in southwestern Queensland and northeastern South Australia. A sequence stratigraphie model for the Hooray is proposed. The basal beds of the Hooray Sandstone are the braided fluvial deposits of the Namur Sandstone Member, deposited during the late Berriasian and earliest Valanginian on a Type 1 sequence boundary developed during the 131.5 Ma sea level lowstand. Two sequences are recognised within the Namur (Namur Nl and N2) with a Type 1 sequence boundary interpreted within the member (128.5 Ma sea level fall). The upper Namur is gradational with the lower Murta Member M6 which forms a transgressive systems tract. The M5 and M4 are highstand systems tract sediments deposited over the maximum flooding surface at the base of the M5 (127.5 Ma condensed section). Low sea levels led to incision of channels basinwards of exposed basement rocks at the end of M4 time (about 126 Ma). Sea level rise led to the gradual Willing of these channels until the southeastern highlands were drowned but islands in the southeast contributed vitrinitic material during mid M3 time, which formed the source for the oil in the Nockatunga area. Reservoir sandstones are developed within the basal M3 incised valley fill sands and in the transgressive microtidal barrier facies sands at the top of the M3. The former can produce stratigraphic traps, whereas the latter form structural traps. Reservoir quality is probably best in the thicker mid 'estuarine' sands due to tidal reworking, and generally poorer in the barrier facies due to little winnowing of fines because of the low tidal range, weak wave activity, and gene-contemporaneous carbonate cementation. During later M3 time, transgression led to the landward movement of barrier bars, forming a generally sheet-like sand body. The top M2 and M3 barriers probably formed in a microtidal environment under a seasonal climate with periodic storm conditions. Following inundation of the islands during M2 and Ml times, organic matter supplied to the Nockatunga area was dominantly finely comminuted, bacterially-altered plant matter and algal material that forms a potentially rich but immature oil source. The 'hot gamma' shales of the Ml are interpreted as the 123.5 Ma condensed section.
PETROLEUM EXPLORATION IN THE PROTEROZOIC BEETALOO SUB-BASIN, NORTHERN TERRITORY
Authors: Lanigan Kevin , Hibbird Shane , Menpes Sandy , Torkington John
Published: August 2017

Exploration over Roper Group outcrop in the McArthur Basin prompted Pacific Oil & Gas to investigate the petroleum potential of the Beetaloo Sub-basin, a 15 000 km2 Proterozoic depression concealed beneath Phanerozoic cover. Since 1989 drilling and seismic has identified a broadly flat-lying sequence with uplifted, eroded margins. A 3 500 m composite Proterozoic section consisting of three sandstone-to-mudstone sequences has been drilled. The lower two sequences comprise conformable units of the Mesoproterozoic upper Roper Group and unconformably overlying them is a previously unknown sequence comprising the informally labelled 'Jamison Sandstone' and 'Hayfield Mudstone', probably of Neoproterozoic age.Organic-rich intervals in the Roper Group mudstones range one to three per cent TOC in the Kyalla Member, and two to seven per cent TOC in the 'Middle' Velkerri Formation. Across most of the sub-basin the oil window lies within the Kyalla Member around 900–1350 m, while the 'Middle' Velkerri Formation is around 2 500 m and well into overmaturity, but may still have potential for gas. Potential reservoirs in the Bessie Creek, Moroak and 'Jamison' Sandstones, and in sandy units within the mudstones, are compromised by diagenesis, but porosities of up to 20 per cent and permeabilities of tens and rarely hundreds of millidarcies have been measured. Encouraging shows were observed in many of these intervals, and small quantities of oil and gas have been recovered in drill stem tests. With only a few targets drilled to date, this frontier area requires more exploration before its hydrocarbon potential can be adequately assessed.
PRACTICAL DEVELOPMENTS IN PREDICTIVE OCEANOGRAPHY OF BENEFIT TO THE OIL AND GAS INDUSTRY
Authors: Black Kerry
Published: August 2017

With improvements in equipment, satellite observations and basic knowledge, oceanographers are becoming more effective in predicting or hindcasting coastal and ocean circulation. Advantages which lead to better environmental outcomes for the oil and gas industry which arise from some of these improvements are discussed with case studies drawn from the Great Barrier Reef and Bass Strait. New developments in knowledge are particularly relevant to issues such as dispersal of produced water, oil spill modelling and environmental impact assessment, including a better understanding of the links between physical processes and biological responses. The case studies form part of a comprehensive hydrodynamic database developed on behalf of the Australian Maritime Safety Authority for an effective numerical modelling response to oil spills.
THE MAIN CHANCES FOR NEW EQUITY
Authors: Charters John G. , Epper Mark S.
Published: August 2017

The main chance for new equity to be raised by Australian petroleum explorers is to:recognise that the unfavourable oil price environment of 1993 will change;in the meantime, understand the manner in which capital markets operate; andbe patient and ready for when it happens.In Australia we can obviously do little about global economic and market conditions, particularly the market for petroleum commodities. This paper is intended to ensure that petroleum explorers continuously consider their position from the perspective of shareholders, potential investors and other market participants so that they are well placed to benefit when capital markets turn in their direction.This paper:Provides an Overview of Australian capital markets;Deals with the Performance of the oil and gas sector within that market;Considers The Three Dimensions of investment decision-making; and, with those foundations,Outlines The Way Forward for this sector, in these difficult times.Equity markets have experienced a period of particularly strong support for equity raisings and there is a real prospect that the Australian stock market will exceed the previous all-time record high.During 1993 many listed oil and gas companies reported improved earnings performance and enjoyed increased share prices, although a flattening of exploration and development activity seems to have followed the lack of significant exploration success in recent years. With the odd exception oil prices have been generally stable in recent years. However, toward the end of 1993, a sharp deterioration in oil prices followed expectations of increased OPEC supply; not withstanding generally widespread faith in medium-to long-term escalation of all commodity prices, and oil prices in particular, investor appetites appear all too easily diverted to other market opportunities.Participants in this industry probably do more searching than finding when it comes to oil and gas reserves. The same is true for raising new capital. We will outline what companies must do to be ready to benefit from the right environment to raise new equity.
DEPOSITIONAL SEQUENCE OF THE WITHNELL FORMATION, DAMPIER SUB-BASIN
Authors: Rasidi J. S.
Published: August 2017

The Late Cretaceous Withnell Formation has attracted very little exploration attention because of the perception that it has poor hydrocarbon potential. This unfavourable perception has arisen from the fact that very little is known about its depositional environment and lithofacies and therefore, its petroleum prospectivity.A sudden fall of relative sea level occurred at the end of the Santonian, and was followed by the deposition of the siliciclastic Withnell Formation. The occurrence of a number of channels and canyons at the base of the formation, over the old shelf and slope on the southern margin of the sub-basin, supports the hypothesis that the Withnell Formation began as a lowstand systems tract. The thickness distribution of the formation and the progradation direction of seismic packages suggest a southeasterly provenance. Correlation of seismic data and well logs, and rock descriptions demonstrate the presence of units deposited during increasing water depths and subsequent highstand systems tract.Much more information, both seismic and well data, is required to establish the facies distribution within the Withnell Formation which may contain sand-prone lowstand facies such as basinfloor or slope fans. The presence of such reservoir facies would enhance the petroleum prospectivity of the Withnell Formation.
NATIVE TITLE: ITS EFFECTS ON PETROLEUM EXPLORATION
Authors: Vickery E.
Published: August 2017

The existence of native title in Australia was recognised by the High Court in its historic Mabo No. 2 judgment on 3 June 1992. Native title is a shorthand expression used to describe those activities pursued by native peoples in connection with their traditional lands, in accordance with traditional law and custom. It could be extinguished in many ways, and once extinguished cannot be revived. Following an intense public debate, the Commonwealth enacted the Native Title Act (NTA) which, for most purposes, commenced on 1 January 1994. The NTA recognises and protects native title, enabling its future extinguishment in only limited cases, principally by government acquisition for public purposes which are actually fulfilled. The High Court decision and the NTA are both constructed around the Racial Discrimination Act 1975 (RDA) which has a dual limb operation. Where laws omit inclusion of people on racial grounds, the RDA uplifts the rights of those people to equate with all other citizens. Where such laws prohibit people on racial grounds, the prohibition provisions will be ineffective. The former limb extends principles of due process and compensation to persons dispossessed of their native title after commencement of the RDA on 21 October 1975. By so doing, existing petroleum tenements probably avoided invalidity, leaving the question of compensation alive for tenements created after that date. Alternatively, the NTA enables those tenements to be validated by legislation, and provides for compensation in appropriate cases. Since 1 January 1994, the RDA imposes a non-extinguishment principle into the general law, whereby granted tenements will not extinguish native title, only displace it for the life of the grant enabling the native title rights to then be resumed. Further Court cases, legislation and proposed international treaties are all now in the course of development, with the combined capacity of expanding native title concepts. Australia is still at the beginning of the evolution of legal recognition of native title.
BASEMENT CONTROL ON THE DEVELOPMENT OF EXTENSIONAL SYSTEMS IN AUSTRALIA'S TIMOR SEA: AN EXAMPLE OF HYBRID HARD LINKED/SOFT LINKED FAULTING?
Authors: O'Brien G.W. , Higgins R. , Symonds P. , Quaife P. , Colwell J. , Blevin J.
Published: August 2017

A series of rift models has been developed for basin systems in Australia's Timor Sea, via the interpretation of newly acquired deep crustal seismic and high resolution aeromagnetic data. These models, which incorporate observations on rift architecture, fault geometries, fault orientation, basement grain and composition, extensional transport direction and reactivation history, have then been iteratively tested by sophisticated analogue modelling experiments. This work has led to the development of a hybrid hard linked/soft linked (basement-involved/basement-detached) fault model. In this model, basement grain is the principal control on the rift architecture that develops, with pre-existing fracture systems acting to establish discrete offsets (hard linkages) between adjacent extensional faults. It is these basement features that produce the recti-linear features which are so common in aeromagnetic data around the Australian margin. With progressively greater extension, the basement-involved, hard linked system exerts no through-going (transfer fault-type) influence over the faulting within the overlying syn-rift phase, with the linkages between the syn-rift faults being 'soft' (via relay ramps, etc). However, as the hard links do act to relay the extensional faults or to flip their polarity (thereby typically producing cross-basinal highs), hard links strongly segment the extensional system into compartments of similar extensional style, and do control the relative positions of source rocks, fluid migration pathways and reservoirs within the rift. During basin reactivation (particularly inversion), the location and geometry of the underpinning, hard linked basement features closely control the locations of the traps that develop in the syn-and post-rift section, and the late-stage fluid flow history. When combined with aeromagnetic data, which define the location of the under-pinning, recti-linear, hard linked basement features, and some regional seismic data, these observations provide a first-pass predictive tool for determining where source depocentres, reservoirs and major structures are likely to be developed in a frontier basin, or where more subtle structural and/or stratigraphic traps might be found in a mature province.
MANAGING CONFIDENTIALITY AND CONFLICTS OF INTEREST IN A COMPETITIVE ENERGY MARKET
Authors: Slattery P.D. , Stammer K.
Published: August 2017

Producers and other participants in the petroleum industry are in the midst of an increasingly competitive energy market. It is now the case that throughout Australia producers of natural gas are competing not just with substitute sources of energy but with one another. No longer do producers only compete for prospective tenements, rather their competitive activity extends from acreage acquisition through to the burner tip. The emergence of deregulation in the gas industry and the opportunities for competitive activity have been discussed at recent APEA conferences.1The aim of this paper is to examine where conflicts between interest and duty may arise between joint venturers who are now directly, or through affiliated companies, competing for marketing opportunities. We examine how and why such conflicts may arise and whether it is possible to manage them while still participating in traditional forms of joint venture exploration, production and in some cases marketing.For example, are producers able to satisfy their obligations of good faith and preserve confidentiality in joint venture exploration and production activities without compromising their ability to independently pursue the marketing of their share of production?
THE EMERGING PHILIPPINE NATURAL GAS INDUSTRY AND OPPORTUNITIES FOR FOREIGN INVESTMENT
Authors: Bomasang Rufino B.
Published: August 2017

The main Philippine energy policy objectives are availability of energy supply; competitive, affordable, and reasonable energy prices; and environmentally compatible energy infrastructure. A key strategy in the pursuit of these objectives is expanded natural gas utilisation.Development of the Camago-Malampaya gas field in offshore northwest Palawan is the vital anchor of the emerging Philippine gas industry. It has proven reserves of 3–4 trillion cubic feet, enough to supply a 3,000 megawatt power plant, but located in very deep water (over 800 m) and far away from the market (requiring 500 km of pipeline). Nevertheless, the developers (Shell and Occidental Petroleum) are prepared to develop the field and build a 24-inch offshore pipeline to transport the gas to power plants in Luzon which independent power producers are likewise prepared to put up, all to be completed by 2001–2002. Total capital requirements from upstream to downstream are estimated at US$4–5 billion.While the initial gas market will be limited to power generation, the government intends to expand the use of gas to the industrial, commercial/residential, and transport sectors. To assure reliable gas supply to the entire gas industry, the government is actively promoting gas exploration and supports LNG importation to supplement indigenous gas.With the government's policy of maximising private sector participation, the gas industry offers tremendous foreign investment opportunities includingindigenous gas exploration/development;pipeline construction;LNG supply and construction/operation of LNG infrastructure;independent power production; anddevelopment of new gas markets.
NEW FRONTIERS IN ENVIRONMENTAL MANAGEMENT
Authors: Kenchington R.A. , Taylor P.
Published: August 2017

Historically much of the debate about the environment and development has been conducted as a series of tactical adversarial encounters from which the champions of environment or development emerge as winners or losers.The concept of sustainable development calls for a different approach in which sectors which have traditionally treated each other as opponents work together to achieve mutually acceptable and enduring outcomes. A wide range of societal goals can be met by integrating social and environmental systems through regional scale multiple use planning.This paper discusses the broad applicability of multiple use management approaches through internationally accepted models and by the example of the Great Barrier Reef Marine Park.The paper outlines the complementary responsibilities of the Australian Nature Conservation Agency (ANCA), the Great Barrier Reef Marine Park Authority and other Commonwealth agencies and the scope for them to work with the Petroleum and other industries to develop sustainable multiple use solutions to complex resource use and conservation issues.
PETROLEUM RESOURCE RENT TAX AND THE NEW FRONTIERS
Authors: Harne C.A. , Vinet J.A. , Baird A.H.
Published: August 2017

The Resource Rent Tax in (RRT) Australia evolved in the late 1970s in a climate of scarcity of world oil and perception of rising oil prices for the next decade and beyond. In the 1990s, where countries are fiercely competing for export markets, many of the fundamental assumptions which underscored the evolution of the tax in Australia are no longer appropriate. The petroleum industry has consistently tendered reasons for the inappropriateness of the tax in certain circumstances. It is essential for Government to reconsider fundamental assumptions underlying the RRT if Australian producers are to remain competitive exporters of oil and gas.
KITCHENS, KETTLES AND CUPS OF HYDROCARBONS, VICTORIAN OTWAY BASIN
Authors: Mehin K. , Link A.G.
Published: August 2017

Evaluation of Early Cretaceous source rocks within the onshore Victoria Otway Basin has revealed that thick, mature shales containing predominantly gas-prone and in local concentrations, oil-prone macerals exist northwest of Portland, in the Tyrendarra Embayment, and around the Port Campbell region.Current results of Rock-Eval, bulk composition, gas chromatography, and biomarker analyses, coupled with geohistory and hydrocarbon generation interpretations, indicate that at least three phases of oil generation and expulsion occurred within the basin. The earliest phase, which coincided with the maximum heatflow in the crust around 100 Ma, resulted in the charging of the existing stratigraphic/shoestring traps of the basin. The second and third phases occurred in the eastern end of the basin at around 85 and 60 Ma. There is also evidence to suggest that structural traps of the eastern areas were formed later, during Oligocene time, and that these traps are probably still receiving late-stage charges of hydrocarbons.Although the sparse well density in the basin has resulted in limited, non-uniforin sampling opportunities, several regions with good Early Cretaceous source rocks can be recognised. Some of these good source rock areas are in close proximity to the several known hydrocarbon shows and producing fields. These current studies, which also include a source rock risk analysis indicating source rock adequacy, show that locations for future exploration could include the Casterton-Portland-Mt Gambier western region, the Peterborough-Port Campbell eastern region, and the prospective close peripheries and offshore extensions of these regions.
GEOCHEMICAL CHARACTERISTICS OF PALAEOZOIC PETROLEUM SYSTEMS IN NORTHWESTERN AUSTRALIA
Authors: Edwards D.S. , Summons R.E. , Kennard J.M. , Nicoll R.S. , Bradshaw J. , Bradshaw M. , Foster C.B. , O'Brien G.W. , Zumberge J.E.
Published: August 2017

Isotopic and biomarker analyses carried out on Cambrian to Permian oils and source rocks in the Arafura, Bonaparte (Petrel Sub-basin) and Canning Basins have been used to geochemically characterise five distinct petroleum systems within the Larapintine and Gondwanan Petroleum Supersystems. The Larapintine 1 Petroleum System is characterised by isotopically light, free hydrocarbons in the Arafura Basin (613Csat = −32 %o Arafura-1) which have been correlated to kerogens of similar isotopic signature within the Middle Cambrian Jigaimara Formation. The richness and maturity of these source rocks indicate that an effective Larapintine 1 Petroleum System may exist in the northern parts of the Arafura Basin. Larapintine 2 oils, with Gloeocapsomorpha prisca-type signatures, are found on the Barbwire- Dampier Terraces and Admiral Bay Fault Zone in the Canning Basin. These oils can be correlated to source rocks in the Lower Ordovician Goldwyer Formation on the Barbwire Terrace and the Bongabinni Formation in the Admiral Bay Fault Zone by their diagnostic odd- carbon-number preference in the C15—CJ9 n-alkanes. Larapintine 3 oils are derived from Upper Devonian marine carbonates in the Canning Basin and Petrel Sub- basin and have a diagnostic biomarker signature which includes a predominance of steranes relative to diasteranes and abundant gammacerane and 30- norhopanes, similar to those observed in the Upper Devonian Gogo and Pillara Formations. Larapintine 4 oils are derived from Lower Carboniferous marine, clay- rich mudstones in both the Petrel Sub-basin and Canning Basin. They are isotopically light (mean δ13C sat = −28 %o) and have a unique terpane signature which has been identified within the Milligans Formation. Gondwanan 1 Petroleum System hydrocarbons, represented here by the Petrel-4 condensate, have a heavy isotopic signature (δ13C sat = −24 %o) which, coupled with an abundance of the diasterane and diahopane biomarkers, indicates derivation from Permian deltaic source facies. Recognition of the diagnostic geochemical components of each Palaeozoic petroleum system has led to the identification of Permian-like isotopic signatres in some hydrocabon accumulations in the Timor Sea that were previously attributed to Mesozoic sources.
OUTSOURCING—A GLOBAL PERSPECTIVE
Authors: Edwards A.G.
Published: August 2017

The global business community is experiencing a massive shift towards adoption of outsourced 'back office' transaction services.Called 'strategic outsourcing', it is driven by the desire of global companies to focus on core activities, and to outsource non-core business processes to specialist global service organisations. It is a significant new market for these organisations, expected to be worth US$40 billion globally, by the year 2000.While cost reduction is a major benefit, the outsource service provider offers value-added service by its ability to re-engineer business processes to world best practice, its ability to rapidly transition the client organisation to new technology, and by extracting the efficiencies of shared services processing.The global service organisations see strategic outsourcing as a natural evolution of their service offering.Outsourcing extends beyond the cost reduction strategies of their consulting service projects: downsizing organisation structure, re-engineering to introduce world class business processes, and transition management for introduction of new technology.By evolving from these project based assignments, into provision of on-going outsourced transaction services, the service organisations have the opportunity to establish a different strategic relationship with their clients, and add value that a client organisation cannot achieve by itself.Cost savings come from the operational efficiencies of shared services processing, and the lower operational cost achieved by specialising the processing of non-core, 'back-office' transactions, and sharing overheads between several clients.Additional business benefits result from the partnering relationship, which can produce new industry specialist services3 valuable to other clients within the same industry.It is likely that the role of the service organisation will further develop, from the position of strategic outsource business partner, to that of general contractor, where a client selects one major supplier as the single point of contact for all outsourced services. The general contractor becomes responsible for all outsourced outputs, subcontracts the services of all other outsourcing organisations, and remains solely responsible for their service provision.
SUCCESSFUL IMPLEMENTATION OF ENERGY PRICE RISK MANAGEMENT
Authors: Simson H.A.
Published: August 2017

Forces are gathering which require companies with significant exposure to financial risks including foreign exchange, interest rates and commodity prices such as energy to actively manage these risks. The paper describes this growing need for risk management and the characteristics of a successful risk management program using oil price by way of example, however, the concepts apply to financial risks generally. These attributes include understanding the nature of specific financial risks and risk quantification; active support and involvement by senior management including the board of directors; sound formulation of policy (including program objectives), procedures and controls; performance monitoring and reporting; compliance monitoring and disclosure of practices to shareholders and the investment community. Energy price risk management programs can be effectively implemented in quite small organisations without the need for significant increases in human resources. Programs rely on financial hedging transactions (often referred to as derivatives) to modify exposure to risk. Successful programs are more likely to be judged on factors like clarity of program objectives and program status, compliance with policy and procedures and avoidance of surprise outcomes rather than simply stand alone profitability of hedging transactions.