bluuebunny/crossref_metadata_2025 huggingface dataset:
PETROLEUM OPERATIONS IN THE ENVIRONMENTALLY SENSITIVE NORTHERN PERTH BASIN, WESTERN AUSTRALIA
Authors: Warris B.J. , Grocke T. , Lane A.
Published: August 2017

Barrack Energy Limited is an Australian company involved in the search for petroleum in Australia. The company's principal area of exploration and production is the northern portion of the onshore Perth Basin in Western Australia. In this area, the company operates four permits and one production licence covering an area of almost 15 000 square kilometres (3.7 million acres).For the period 1987 to 1989, Barrack Energy Limited acquired 1238 line km of seismic in the northern Perth Basin. This was conducted in fourteen surveys extending from Lancelin in the south to Dongara in the north.Petroleum exploration and production operations in the northern Perth Basin are highly visible and require painstaking and careful planning, permitting and negotiation to achieve the multiple land use goals of minimum disturbance to private landowners and minimum impact and zero long term effects on the environment.Due to the large areas of Vacant Crown Land and flora and fauna reserves in the northern Perth Basin, the impact of seismic line clearance upon the terrain was a major consideration. Barrack Energy Limited decided to experiment with various mechanical systems to clear seismic lines in order to determine the optimum operational and environmental technique. The bulldozer/ grader combination proved to be the most practical line clearance method available. The dozer need not be a tool of destruction and when operated correctly does no more damage than other methods tried.At all times Barrack Energy Limited has striven to ensure that the impact on the surrounding countryside by its exploration and production activity is kept to an absolute minimum. The company works closely with the local community to ensure that the local residents are comfortable at all times with the company's operating methods.
DISCOVERY OF THE WANAEA AND COSSACK OIL FIELDS
Authors: Bint A.N.
Published: August 2017

Exploration of the Dampier Sub-basin on the North West Shelf of Australia commenced with a reconnaissance seismic survey in 1965. In 1969 Madeleine-1, the first well drilled on the Madeleine Trend, encountered water bearing Upper Jurassic sandstones. Following acquisition of a regional grid of modern seismic in 1985 and 1986, and comprehensive hydrocarbon habitat studies, the Wanaea and Cossack prospects were matured updip from Madeleine 1. They were proposed to have improved reservoir development and an oil charge.The Wanaea Oil Field was discovered in 1989 when Wanaea-1 encountered a gross oil column of 103 m in the Upper Jurassic Angel Formation. The well flowed 49° API oil at 5856 BPD (931 kL/d) with a gas-oil ratio of 1036 SCF/STB. Two appraisal wells were drilled in the field in 1990.The Cossack Oil Field was discovered in 1990 when Cossack-1 encountered a gross oil column of 54 m also in the Angel Formation. The oil-water contact is 18 m deeper than in Wanaea-1. Cossack-1 flowed 49° API oil at 7200 BPD (1145 kL/d) with a gas-oil ratio of 98 SCF/STB.The Angel Formation reservoir consists of mass flow sandstones interbedded with bioturbated siltstones. Sandstone porosities average 16 to 17 per cent for both the Wanaea and Cossack Fields. Permeabilities average about 300 mD at Wanaea and about 500 mD at Cossack.An extensive 3-D seismic survey was conducted over the Wanaea and Cossack Fields in 1990. Final reserves calculations await interpretation of this survey, but it is clear that the combined Wanaea and Cossack oil reserve is the largest outside Bass Strait.
THE YAMMADERRY, COWLE AND ROLLER DISCOVERIES IN THE BARROW SUB-BASIN, WESTERN AUSTRALIA
Authors: McLerie M.K. , Tait A.M. , Sayers M.J.
Published: August 2017

The TP/3 Part I permit in the Barrow Sub-basin has been held by WAPET since 1952. Improvements in seismic quality and oilfield economics in the early 1980s resulted in the 1985 Saladin oil discovery, which subsequently led to the Yammaderry, Cowle and Roller discoveries.Yammaderry-1, drilled in 1988, encountered 16.5 m of gas capping a nine metre oil column. In 1989, Cowle-1 penetrated a 14 m oil column and tested at 1016 m3 (6390 BBL) of oil per day. Roller-1, drilled in 1990, encountered six metres of gas capping nine metres of oil and tested at 866 m3 (5450 BBL) of oil per day. Roller-2, deviated downdip to find the oil/water contact, proved an 18 m oil column, confirmed later by Roller-4.Early Cretaceous Barrow Group deltaic sandstones are the reservoirs for the Saladin, Yammaderry, Cowle and Roller oil fields. The Barrow Group is overlain by the Mar- die Greensand, the basal unit of the Muderong Shale which forms the regional seal. The transitional acoustic character of the Mardie Greensand and its thickness, variable fluid saturation and lithology, cause problems in picking a top Barrow Group event. Vertical Seismic Profiles acquired in the Yammaderry, Cowle and Roller wells have helped tie the wells to the seismic data.With Saladin on stream, and Yammaderry and Cowle under development, a major seismic survey was completed in late 1990 to delineate Roller and to detail prospects for future drilling in the revitalised TP / 3 Part 1 permit.
TECTONOSTRATIGRAPHIC EVOLUTION OF THE SOUTH-EAST GIPPSLAND BASIN
Authors: Duff B.A. , Groilman N.G. , Mason D.J. , Questiaux J.M. , Ormerod D.S. , Lays P.
Published: August 2017

Evolution of the south-east Gippsland Basin since ca. 96 Ma has been governed by the interaction of three distinct processes:re-organisation of regional plate boundaries at 96, 80 and 50 Ma, registered as major angular unconformities or megasequence boundaries;intra-basin response of cover to basement-controlled deformational phases, registered as the sequence boundaries within these megasequences; andthe more subtle balance between regressive sedimentation associated with these phases and the transgressive deposition associated with longer-term eustatic sea level rises.The Golden Beach Megasequence (seismic sequences UK1 and UK2) accumulated syntectonically in an extensional setting characterised by an orthogonal array of north-northeast trending transfer faults and associated normal faults. Major compressional tectonism at ca. 80 Ma terminated this regime, initiating a modified mosaic of stratotectonic domains which controlled deposition of the Latrobe Megasequence.The seismic sequences within this megasequence display two types of cyclicity distinguishing intra-Campanian to Top Maastrichtian sequences (UK3-UK5) from early Tertiary sequences (PL1, PL2 and EO1). The sequence boundaries are considered to be the expression of recurrent compressive deformational phases. They are demonstrable as angular unconformities in transpressional and pull-apart structures in domains within which deformation was focused over the older extensional grain.The ca. 50 Ma Top Latrobe megasequence boundary appears to mark the transition from a basement-coupled deformational style characteristic of the Latrobe Megasequence, to a basement-decoupled inversion style of deformation during deposition of the Seaspray Megasequence (post-50 Ma).Seismic sequence boundaries, at least within basins such as the Gippsland, are therefore the stratigraphic expression of deformational phases rather than signatures of global sea-level changes. Eustacy is not invariably a shorter-term process than basin tectonism, nor is it the sole or main determinant of depositional style.
SEQUENCE STRATIGRAPHY OF THE EASTERN OFFICER AND ARROWIE BASINS: A FRAMEWORK FOR CAMBRIAN OIL SEARCH
Authors: Gravestock D. I. , Hibburt J.E.
Published: August 2017

The Early Cambrian eastern Officer and Arrowie Basins share a common sequence stratigraphic framework despite their contrasting settings. The Arrowie Basin was initially a shallow marine shelf between two land masses with moderate to abrupt shelf-ramp and shelf-slope profiles deepening to the north and south. Tectonic activity subsequently restricted open marine access to the north resulting in evaporite and red bed deposition. In the eastern Officer Basin epeiric sea sediments had open marine access only to the northeast. The palaeoslope was low and surrounding land supplied abundant siliciclastics. Following marine withdrawal alkaline playa lake and evaporitic mudflat deposits spread across the hinterland. Potential source rocks in the Arrowie Basin are thick transgressive and early high-stand deposits of the lowest three sequences. Organic carbon content may be highest (on slender evidence) where marine circulation was restricted. Carbonate reservoir quality on the shelf depends on subaerial exposure during marine lowstands. Prograding highstand sands, carbonate grainstones, and syntectonic channel deposits have untested reservoir potential. In the eastern Officer Basin potential source rocks are thin but widespread. Oil has been generated in the playa lake sediments. Fluvial, aeolian and shoreline sandstones, and those interbedded with carbonates, have excellent reservoir characteristics. The interbedded sands are thin but may be grouped near sequence boundaries. Lowstand carbonate breccias have generally unpredictable reservoir quality. Major differences in source and reservoir bed distribution between these basins, which share the same cycles of relative sea level change, are: palaeoslope, proximity to open marine conditions, duration of subaerial exposure and availability of terrigenous clastics.
PETROLEUM PROSPECTIVITY OF PACIFIC ISLAND ARCS: SOLOMON ISLANDS AND VANUATU
Authors: Falvey D.A. , Colwell J.B. , Coleman P.J. , Greene H.G. , Vedder J.G. , Bruns T.R.
Published: August 2017

The limited petroleum search which has taken place in Pacific island arc areas has focused mainly on deep forearc or intra-arc basins, so far without success. Very few exploration wells have been drilled. The interpretation of the results of marine geophysical and geological surveys and research carried out in the Solomon Islands and Vanuatu, southwestern Pacific, suggests that the thick volcaniclastic depocentres probably lack major petroleum potential. However, the margins of the basins are likely to be much more prospective. Marginal marine environments bordering the basins may generate immense quantities of organic material favourable to petroleum generation, and this material can be fed into deep basins adjacent to reefal reservoirs. In the Solomons and Vanuatu, where no exploration wells have been drilled, this marginal marine play greatly enhances prospectivity - and, by extrapolation, also that of other arc systems. In particular, source beds may be present. Promising target areas in the Solomons and Vanuatu include Iron Bottom Basin adjacent to Guadalcanal, the southwestern flank of the Solomon High from Choiseul through Santa Isabel - Florida Islands - northern Guadalcanal (especially the Manning Strait area), the area between the Shortland Islands and western Choiseul, Vanikolo Basin, the western margins of the North and South Aoba Basins, and possibly the Malekula and Mbokokimbo Basins.
RECENT DEVELOPMENTS IN BOREHOLE SEISMIC SURVEYS, OFFSHORE NORTHERN AUSTRALIA
Authors: Sutherland A. , Smith P.M.
Published: August 2017

Offshore northern Australia has long been recognised as a region where the quality of seismic data is frequently adversely affected by several factors which include the following.The presence of a hard water bottom.The presence of carbonate units in the Eocene and Paleocene which are highly reflective and reduce the amount of seismic energy which penetrates to the deeper target horizons. These also produce interbedded multiples which are difficult to remove from the seismic data.Complex shallow faulting which causes ray path distortion and disperses the seismic energy.The confidence with which well data can be tied to the poor quality seismic data through well velocity surveys is further reduced by the complicated deeper faulting associated with the structures drilled and the low acoustic impedance contrast at the target horizon.Borehole seismic surveys provide the most reliable link between the subsurface intersected by a well and seismic data. The recent introduction of a new borehole seismic tool has improved the quality of Vertical Seismic Profiles (VSPs) acquired. This tool has three component geophones mounted in a sensor module which is isolated from the main body of the tool by springs which minimise the effect of source-generated noise.This reduction in sensitivity to the source-generated noise has allowed the introduction of more powerful source arrays to improve the signal to noise ratio. The use of source arrays has increased the bandwidth of the seismic impulse and decreased the effect of the bubble pulse.The quality of the horizontal component VSP data recorded using the new tool has also improved significantly and this has increased the possibility of detecting mode converted reflected and transmitted shear wave energy and the more accurate measurement of shear wave velocities.
THERMOLUMINESCENCE GEOTHERMOMETRY — A CASE STUDY OF THE OTWAY BASIN
Authors: Ypma Peter J. , Hochman Mark B.M.
Published: August 2017

The thermoluminescence (TL) of quartz of detrital origin in a sedimentary basin is affected by time and temperature in two different ways:TL due to natural radiation (NTL) shows a first glow peak (which is commonly also the dominant peak) the glow temperature of which is a function of ambient radiation temperature and time. Progressive burial and increase of temperature results in a thermally 'cleaned' TL peak. Uplift, erosion or a decrease of temperature produces a new TL peak of lower temperature, with or without retention of the earlier formed TL peak. The glow temperature of those peaks can be evaluated in terms of time and ambient temperature of the basin. A comparison with palaeotemperatures estimated from vitrinite reflectance (VR) and apatite fission track analysis (AFTA) has shown very good agreement between NTL, VR and AFTA for those wells in the Otway Basin where present temperatures are at their maximum. In the case of uplift and a cooling trend the NTL temperatures reflect the most recent thermal regime, plus some effects from earlier thermal stages.Artificial TL (ATL) shows at basin temperatures exceeding 50°C a gradual change of intrinsic TL parameters. The changes are probably due to a decrease in the number of certain defects. The ATL effects are cumulative and reflect the whole thermal flux. In this sense ATL is comparable with VR. Although absolute calibration of ATL is not yet possible, relative changes due to differential uplift, erosion and cooling can be interpreted once the prevailing thermal gradient is known from NTL data. In this way, ATL indicated an uplift differential of 500 m between certain wells in the Otway Basin. The same results are confirmed by VR and AFTA data.
FRACTAL GEOMETRY, RESERVOIR CHARACTERISATION AND OIL RECOVERY
Authors: Taggart I.J. , Salisch H.A.
Published: August 2017

Reservoir heterogeneity is a dominant factor in determining large-scale fluid flow behaviour in reservoirs. Engineering estimates of oil production rates need to acknowledge and incorporate the effect of such heterogeneities. This work examines the use of fractal-based scaling techniques aimed at characterising heterogeneous reservoirs for simulation purposes. Well log data provide suitable fine-scale information for estimating the fractal dimension of reservoirs as well as providing known end- point data for interwell property value interpolation. Fractal techniques allow this interpolation to be performed in a manner which reproduces the same correlation structure as that found in the original well logs. Conditional simulation in these property fields allows the interaction between reservoir heterogeneity and fluid flow to be studied on a range of scales up to the interwell spacing. Analysis of results allows the calculation of effective reservoir properties which characterise the reservoir in terms of large-scale performance.
DEVELOPMENT AND FIELD EVALUATION OF A NEW MICROBIAL EOR CONCEPT
Authors: Sheehy Alan J.
Published: August 2017

For over 40 years it has been speculated that bacteria can facilitate, increase or extend oil production from petroleum reservoirs. This speculation was supported in the laboratory by dramatic increases in oil recovered from experimental systems and in the field by anecdotal accounts of improvements in oil production. Most of these studies were poorly conceived and inadequately controlled. This drew industry criticism and created an environment where proposals to implement microbiologically enhanced oil recovery (microbial EOR) were summarily dismissed. The program implemented for the Alton Field, Surat Basin, was designed to overcome industry scepticism and document unambiguously in the field the effectiveness of a new microbial EOR strategy called Biological Stimulation of Oil production (BOS). An approximate 40 per cent increase in oil production has been sustained, compared to control operations on the same well, for eighteen months.The thrust to introduce pilot and field programs of BOS is compelling. BOS shares the advantages common to all biotechnologies in exploiting the extraordinary growth potential of microorganisms, providing flexibility through the extreme diversity of microbial metabolites and using cheap feedstocks. The BOS process generates ultramicrocells from those bacteria present naturally in the reservoir to be treated. This promotes injectivity, dispersion and persistence of the BOS system in the extreme environments which characterise petroleum reservoirs. The nutrients injected with the ultramicrocells result in metabolites forming within the bacterial cell surface. These metabolites cause re-profiling of the formation through the generation of emulsions and the development of concentrated surfactants at the oil-water interface.Ecological strategies designed to negate previously documented problems in the application of microbial EOR have been shown to be effective in laboratory experiments and field applications. Overcoming environmental extremes and developing persistence of beneficial organisms have been given special attention.
THE DEVELOPMENT OF NATURAL GAS IN VICTORIA
Authors: Baker Alan
Published: August 2017

The development of natural gas in Victoria is mainly that of the Bass Strait gas fields discovered by Esso and BHP, with the former as operator, and of the Gas and Fuel Corporation of Victoria.Since discovery of natural gas in 1965, the market has grown to the delivery in 1989 of 193 petajoules (PJ), consisting of 157 PJ to the Corporation and 36 PJ for use by the State Electricity Commission for Esso's and BHP's own use.This development has includeed the consolidation of gas utilities in Victoria into one entity and aggressive competition to replace oil in industry and space heating and electricity in water heating. Price advantages conferred through oil price increases in the late 1970s were countered in the early 1980s by the Government realising the opportunity cost through increased taxation.Consideration of the likely growth in the Victorian and Australian economies allows some prediction of the future development of natural gas in Victoria to 2010. While the market is expected to increase at a rate of 3.2 per cent per annum in the medium term, this will fall to 2.3 per cent over the long term.Changes in the numbers of gas appliances in each home and their annual usage, competition from electricity in the hot water market, demand management, losses of some industries, new markets such as NGV and cogeneration and the effects of greenhouse gases will all have their effects.
BARROW ISLAND OILFIELD ENVIRONMENTAL REVIEW — 25 YEARS OF LEARNING
Authors: Lagdon R.D.
Published: August 2017

Barrow Island, off the north-west coast of Western Australia, was declared a Class 'A' Nature Reserve for the protection of flora and fauna in 1908. Since 1963, West Australian Petroleum Pty Limited (WAPET) has conducted oil exploration and production operations on the island, producing over 235 million barrels of oil. The fact that the introduction of exotic plants and animals has been prevented and the island's full suite of native species remains intact is due to a rigorous environmental program. In developing and refining that management program over the past 25 years, WAPET has pioneered environmental management and rehabilitation techniques. In 1988-89, WAPET carried out a comprehensive review and audit of its management procedures to satisfy itself that its operations continued to meet the high environmental standards expected of our industry. The review critically examined the impacts of operational procedures including seismic exploration, gravel extraction, quarantine, rehabilitation and workforce education to determine the effect of the operations on the conservation values of Barrow Island. The Barrow Island operation demonstrates that with proper management and planning, development and conservation are not incompatible.
THE DEVELOPMENT OF A TOTAL HAZARD CONTROL PLAN FOR AN LNG SITE
Authors: Goggin Denys
Published: August 2017

Australia's North West Shelf Project is based on the development of major gas reserves discovered in the early 1970s in deep water some 130 km off the coast from Dampier, Western Australia.The project was developed in two phases. The Domestic Gas Phase, completed in 1984, supplies pipeline gas to the State Energy Commission of Western Australia for distribution in the south-west of the State. The Liquefied Natural Gas (LNG) Phase involves the export of LNG to eight Japanese power and gas utilities under 20-year Sale and Purchase Agreements. The production and export of LNG commenced in 1989.A Total Hazard Control Plan (THCP) has been developed for the project's onshore and offshore facilities to ensure that all hazards which could affect public safety outside the plant boundary are identified and controlled for the life of the site.The THCP applies to all sites, including the trunkline, onshore gas treatment plant, King Bay supply base and North Rankin A offshore platform. The objectives of the THCP are: to identify the hazards that exist together with their potential consequences; to list the policies and procedures which control the hazards and assign responsibility within the organisation to ensure that those policies and procedures are implemented; to provide verifiable assurance to Government that the Project Operator, Woodside, comprehensively and systematically controls all foreseen hazards to public safety, at the level of 'reasonably practicable'.Compliance with the THCP is verified using a structured auditing programme involving both internal and external audits.
AN ANALYSIS OF AUSTRALIAN PETROLEUM TAXES
Authors: Hattersley Ted
Published: August 2017

An algebraic analysis is employed to evaluate the effects of Australian petroleum taxes on the economics of typical exploration and development ventures, particularly the degree to which their imposition may inhibit investment which would otherwise be undertaken. Taxes which do not deter investment are generally termed neutral and the petroleum taxes, which are levied in conjunction with income tax, may be considered 'neutral' if they do not deter investment which would be undertaken if income tax alone were imposed.The Brown tax is a properly neutral tax when applied alone. When assessed in advance of income tax, however, it accentuates the distortion of income tax itself and its impact is non-'neutral'. Resource Rent Tax (RRT) is a derivative of the Brown tax and exhibits the same characteristic in its theoretical form. In both cases, 'neutrality' could be restored by assessing the secondary tax after a notional income tax, the secondary tax payments being non-deductible for actual income tax. In its practical application, RRT also presents difficulties in the establishment of an appropriate threshold rate and an appropriate ring fence. As applied prior to July 1990, it discouraged exploration because of the permit ring fence applied to the deduction of exploration expenditure. The widening of exploration deductibility to the corporate level from July 1990 has reduced this problem for companies with current RRT liabilities, but the concurrent reduction in the threshold rate on project expenditure will tend to inhibit developments by such companies. Companies without assured RRT liabilities will not benefit greatly from the corporate ring fence, particularly with the retention of GDP factor compounding on expenditure incurred more than five years in advance of the award of a production licence, yet will also be affected by the lower project threshold rate.Royalty makes no pretence at neutrality, yet it exhibits a similar distortionary effect to a theoretical RRT, limited deductibility of costs being offset by the lower rate. Excise may introduce large distortions and its satisfactory application depends on matching the rate and exemption scales to the technical and economic environment.
RAISING EQUITY CAPITAL UNDER THE CORPORATIONS ACT
Authors: Lee Paul W.
Published: August 2017

The Corporations Act 1989 (Cwlth) ('the Act'), which is expected to come into force on 1 January 1991, will introduce major changes to the regulation of fund-raising by a corporation.The notion of an offer to the public, which governs whether a prospectus is required to be issued or not under the Companies Code 1981 ('the Code'), will be replaced by a blanket prohibition on offers or invitations for subscription or purchase of securities, subject to enumerated exclusions. Consequently, rights issues and dividend reinvestment schemes will be required to be accompanied by the issue of a prospectus, as will offers of prescribed interests.While farm-outs and unincorporated joint ventures fall within the present definition of 'prescribed interests', the Australian Securities Commission (ASC) has indicated that Regulations will be promulgated to exempt them.The contents of prospectuses will be governed by a general disclosure provision together with a catalogue of factors designed to ensure that the information supplied in a prospectus is directly proportional to the informational needs of the proposed offerees.The Act has expanded the civil liability of persons associated with the preparation of a prospectus by increasing both the class of potential plaintiffs and the class of potential defendants.To fine-tune the operation of the scheme and the significant changes wrought, the legislature may have to resort to the promulgation of regulations as well as amendment by statute.
PERTH BASIN REJUVENATED
Authors: Hall Peter B. , Kneale Robert L.
Published: August 2017

The northern Perth Basin is an area where recent seismic advances combined with new geological insight, have led to exploration success with a significant new gas field discovery at Beharra Springs and a number of other minor discoveries. This paper outlines 'new concepts' with regard to stratigraphy and structure and how this has been balanced with the commercial environment to rejuvenate exploration in the northern Perth Basin. The Perth Basin is unique in Australia, as running through the middle of the Basin is the West Australian Natural Gas (WANG) pipeline which will be operating at approximately 26 per cent of its capacity in 1992. With the deregulation of the natural gas market in 1988, supply of gas to the Western Australian market via the State Energy Commission of Western Australia (SECWA) pipeline from the Carnarvon Basin, and in particular, the North West Shelf project, can now be balanced with supply from the onshore Perth Basin carried by the WANG pipeline.The minimum economically viable gas field in the northern Perth Basin is calculated to be 15 BCF (16.05 PJ) and the expected median field size is 50 BCF (53.5 PJ) of recoverable gas. Based on the historical success rate of one in eight, typical finding costs are 12 c/MCF (12 c/GJ).In the 1990/91 financial year, eight onshore exploration wells were drilled in Western Australia of which five were drilled in the northern Perth Basin. Provided the market access and opportunities remain, it is anticipated that the recent technological developments will sustain exploration and development of the onshore northern Perth Basin.
THE EXPLORATION AND APPRAISAL HISTORY OF THE KATNOOK AND LADBROKE GROVE GAS FIELDS, ONSHORE OTWAY BASIN, SOUTH AUSTRALIA
Authors: Parker K. A.
Published: August 2017

The discoveries of the Katnook Field and, later, the Ladbroke Grove Field were significant milestones for hydrocarbon exploration in the southeast of South Australia as well as for the Otway Basin in general. The initial 1987 discovery at Katnook-1 of a relatively shallow gas accumulation in the basal part of the Eumeralla Formation was eclipsed in late 1988 at the Katnook-2 appraisal stage where deeper and more significant gas reserves were discovered in the Pretty Hill Sandstone.Technological improvement, in seismic acquisition, in particular, use of longer offset configurations and higher fold, and in filtering and correction techniques at the processing stage, are discussed in relation to improved geologic understanding. These aspects ultimately led to drilling success in both exploration and appraisal.At the deep Katnook discovery stage several significant problem areas remained unresolved. These related to uncertainties in vertical distribution of gas pay, level of a gas-water contact, and unreliable reserve estimates the result of the inability of conventional log analysis techniques to distinguish gas-bearing from water-bearing sands. Both in the evaluation of Katnook-2 and at the Katnook-3 appraisal stage, expensive cased-hole testing programs were undertaken to determine the size, extent and producibility of the gas accumulation. A key development between drilling Katnook-2 and Katnook-3 was the discovery of carbon dioxide-rich gas at Ladbroke Grove during 1989 in an adjacent structure to the south.The Katnook Field was the first commercial gas field development in the southeast, South Australian part of the Otway Basin, with gas sales commencing in March 1991, within a year of completing field appraisal. The discoveries, and subsequent development, have led to a renewed focus on the Otway Basin as a prospective hydrocarbon province.
THE HV11 3-D SEISMIC SURVEY: SKUA – SWIFT AREA GEOLOGY REVEALED?
Authors: Fittall A.M. , Cowley R.G.
Published: August 2017

The 4630 km of HV11 3-D seismic survey data, shot over the Skua and Swift fault blocks in Timor Sea licence AC/L4, reveals details of Tithonian faulting not evident previously. The HV11 survey provided 10 times the data density of previous coverage and significantly improved data quality through the recording of lower frequencies and use of accurate navigation systems and high resolution processing parameters.Tithonian faulting is revealed as a series of northeast-trending en echelon faults overprinting a deeper, north-northeastern, possibly latest Triassic, trend which defines the major fault block boundaries. Transfer of fault throw between en echelon segments appears to be by strike ramps with no evidence for cross-cutting transfer faults. Skua Field fault geometries preclude Upper Jurassic, right lateral strike-slip tectonics. Semi-regional fault trends also have an en echelon style with transfer of fault throw by strike ramps. Escarpments developed along the Tithonian faults are also evident on the HV11 data.The direction of Tithonian extension is interpreted to be oblique to the deeper fault trend, giving rise to the en echelon Tithonian fault style. Each en echelon segment appears to control an hydrocarbon accumulation, which may be due to fault-independent drape over palaeotopographic relief.En echelon Miocene faulting, incisement and depositional mounding in the Puffin Formation are also detailed by the HV11 seismic data. The HV11 survey demonstrates the value of acquisition of 3-D seismic data as an exploration tool in an area of complex and subtle structural geology.
SEISMIC STRATIGRAPHIC EVALUATION OF A NEOCOMIAN SUBMARINE FAN SYSTEM, BROWSE BASIN, NORTH WEST SHELF
Authors: Miller L.R. , Stuart W.J.
Published: August 2017

A possible submarine fan system of Valanginian age occurs in the south of the western half of Permit WA-212-P in the Browse Basin. Seismic mapping and interpretation have allowed the recognition of five seismic facies which are considered representative of this fan system.The five seismic facies are the upper-middle fan braided channel facies, the upper-middle fan braided interchannel facies, the lower fan channel facies, the lower fan sheet facies, and the lower fan lobe fringe facies. The reflections of the upper-middle braided channel fan facies are discontinuous, disrupted, convex up, low amplitude and high frequency. The interchannel facies has reflections that are concave up, continuous, low frequency and moderate to high amplitude. The lower fan channel facies are recognised by convex up, discontinuous, high frequency and low amplitude reflections. The lower fan sheet facies is noted by mounded configurations with continuous, moderate to high amplitude, moderate frequency reflections. The lower fan lobe fringe facies reflections are flat, often shingled reflections with moderate discontinuity, moderate to high amplitude and low to moderate frequency.Since no wells penetrate the submarine fan, the interpretation is based on seismic reflection configurations which are considered typical of submarine fan segments. The interpreted ancient submarine fan occurs on the basin floor adjacent to a probable ramp type margin, and manifests shape and setting consistent with known submarine fans, such as the Eocene Frigg Fan of the North Sea, and the Lower Cretaceous Barrow Group turbidites in the Carnarvon Basin.Seismic facies mapping, in conjunction with sequence stratigraphy concepts, is particularly useful in areas such as the Browse Basin where considerable marine shale sections exist with little structure, and sequences with reservoir potential continue to be a problem to locate. For instance, in Caswell-1, a well drilled in 1977 immediately north of the permit area, 200 barrels of oil flowed from thin sands within a shale sequence of Albian age. Results of this study indicate that local seismic reflection signatures may be indicative of potential sandstone reservoirs in the vicinity of the study area.
TUBRIDGI — HOW DO SMALL COMPANIES OBTAIN PROJECT FINANCE
Authors: Wheatley A.D.M.
Published: August 2017

In the current climate, petroleum companies with limited financial resources can expect to experience considerable difficulty in funding their projects. Without the presence of a substantial partner, able and prepared to guarantee completion, projects will need to be exceptional to attract finance. However, the strengths of the Tubridgi Gas Project (Tubridgi) together with the nature of the partnership between Barclays and the sponsors ensured that Tubridgi could proceed without support from a major.A financier's involvement in the final stages of project evaluation and planning can facilitate the project's financing. The early participation by a financier can ensure that critical agreements and studies are bankable, without the need for time consuming and expensive redrafts or additional programs, and may allow the financier to optimise the funding structure to the project sponsor's requirements. This situation can enable the project's sponsors to take advantage of the financier's experience as a reliable source of technical and commercial advice during the process of the technical audit whilst providing the financier with a high degree of comfort regarding the project.The focus for financiers is almost exclusively upon project risk whereas sponsors are able to consider the balancing rewards of 'upside potential'. Without careful management, this difference of viewpoint can lead to difficulties, with financiers requiring a level of certainty, in resource appraisal and project completion, beyond many project sponsors' expectations. Careful appraisal and mitigation of risk during project planning and execution enabled Tubridgi to proceed without the need for the sponsors to 'give away the farm'.
RISK MANAGEMENT — STRIKING THE BALANCE
Authors: Ashton R. S.
Published: August 2017

The conduct of industry operations involves, inevitably, risk to a corporation's assets, earnings and people. Additionally, there will always be liability risk. The management of these risks is an essential requirement for proper management of a corporation in general. Risk management does not merely involve buying insurance. It requires that there be careful identification and evaluation of risk followed by determination of how that risk might be controlled, financed or transferred. The control of a risk may include elimination, containment or training. Financing a risk might be achieved out of some special fund, operating revenue, borrowings or perhaps even by the use of a captive insurer or a combination of all of these. Risk transfer can be effected by contract, by exercise of legal rights or by the purchase of insurance.There is a wide range of insurance options designed to provide a measure of protection and management of asset risk, earnings risk, people risk and liability risk. The key, in the end, is striking the balance between the extremes of unacceptable risk on the one hand and not doing business at all on the other.
TECTONIC EVOLUTION OF THE GIPPSLAND BASIN AND HYDROCARBON POTENTIAL OF ITS LOWER CONTINENTAL SHELF
Authors: Megallaa Maher
Published: August 2017

Tectonic evolution of the Gippsland Basin, par­ticularly for the 120 to 66 Ma period, is reviewed based on the interpretation of BMR Continental Mar­gin Seismic data and industry seismic and well infor­mation over the continental shelf. It is revealed that the eastern limit of the Early Cretaceous (120-97 Ma) rift is the Gippsland Rise—a new tectonic element. The Rise is part of a regional deep-seated metamor­phosed Palaeozoic lineament belonging to the Tasman Fold Belt upon which the Strzelecki Group onlapped from the west. Two newly-identified transfer fault zones named here, the Eastern Gippsland Margin Transform and the Cape Everard Transfer Fault, bound the rise from the east and the west respectively.In a second phase of rifting (97-80 Ma) the following tectonic events took place:A narrower rift was incised at the onset of this phase parallel to the initial rift; The Gippsland Rise became unstable;A new NW-SE tensional regime commenced;The Southern Platform collapsed (in the Cenomanian) and the Southern Ocean accessed the three Bass Strait basins; Towards the end of this episode (in the Campanian) the Southern Platform and the Gippsland Rise emerged, andThe Northern and Southern Grabens (new names) were incised in the Gippsland Rise connecting the newly formed Tasman Sea to the basin.Ingredients necessary for potential hydrocarbon exploration in the lower shelf and upper slope such as source, reservoirs, seal, trapping mechanism and re­charge do exist but require additional seismic and geological evaluation.
A KEY TEST OF OTWAY BASIN POTENTIAL: THE EUMERALLA-SOURCED PLAY ON THE CHAMA TERRACE
Authors: Tupper N.P. , Padley D. , Lovibond R. , Duckett A.K. , McKirdy D.M.
Published: August 2017

Geochemical analysis, petrographic examination and wireline log interpretation have identified intervals within the lower Eumeralla Formation of the Otway Group (Early Cretaceous) with good source potential. The sequence has a maximum penetrated thickness of 260 m and consists of thinly interbedded coal and siltstone deposited in peat swamp and lacustrine environments. Vitrinite is the dominant maceral present in the coal although the proportion of more oil-prone liptinite commonly exceeds 10 per cent. This is consistent with the intermediate Type II/ III kerogen composition indicated by Rock-Eval and is comparable with data from proven terrestrial oil-productive source rocks in the Gippsland and Cooper Basins. The siltstone is organically-lean but has some algal input. Algal-rich lacustrine source rocks could be developed nearer the basin centre.Regional stratigraphic, structural and thermal modelling studies highlight the exploration potential of the Chama Terrace in the northwest Otway Basin. Structures on the terrace are ideally situated to receive a hydrocarbon charge from mature Eumeralla Formation source rocks in fault blocks on the downthrown side of the Tartwaup Hingeline.Seismic mapping of offshore permit EPP 24, and adjacent onshore permit PEL 40, has delineated several large fault blocks where Crayfish Subgroup (Otway Group) reservoir is juxtaposed against, and sealed by, the lower Eumeralla Formation sequence. Drilling scheduled for late 1992 will determine the credibility of the Eumeralla-sourced play and provide a key test of the ultimate hydrocarbon potential of the Otway Basin.
THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA
Authors: Warris B. J.
Published: August 2017

There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.
TECTONIC SETTING, STRATIGRAPHY AND HYDROCARBON POTENTIAL OF THE BEDOUT SUB-BASIN, NORTH WEST SHELF
Authors: Lipski Paul
Published: August 2017

The tectonic and depositional histories of the Bedout Sub-basin are closely related to more widely explored areas of the southern North West Shelf, i.e. the Barrow and Dampier Sub-basins. The Mesozoic Bedout Sub-basin onlaps and overlies the Palaeozoic offshore Canning Basin sequence. Four distinct tectonic regimes characterised the Triassic, Early to Late Jurassic, Late Jurassic to Late Cretaceous, and Tertiary to present:During the Triassic, the Bedout Sub-basin was part of a broad intracratonic downwarp that also encompassed the Barrow, Dampier and Beagle Sub-basins. A thick sequence of Locker Shale and Upper and Lower Keraudren Formations (Mungaroo Formation equivalent) was deposited.During the Jurassic rifting phase, the Bedout Sub-basin was a subsiding rim basin, landward of the uplifted rift margin. Sedimentation was dominated by a thick sequence of fluviodeltaic to marginal marine deposits.In the post-break-up phase from the Callovian to latest Cretaceous, a transgressive regime resulted in deep open marine conditions with widespread claystone and minor carbonate deposition over the southern North West Shelf.Through the Tertiary to the present, shallow shelf conditions prevailed and sedimentation was dominated by a thick prograding carbonate wedge.Hydrocarbon source is provided by a thick sequence of Triassic Locker Shale and Lower Keraudren Formation. The Locker Shale is presently mature for hydrocarbon generation over most of the Bedout Sub-basin and has the potential to generate both oil and gas. The Lower Keraudren Formation is a mature source mainly for gas/condensate in deeper sections of the sub-basin. Jurassic marine claystones, which represent a prolific source in the Barrow and Dampier Sub-basins, are not present in the Bedout Sub-basin.Reservoir rocks exist in the Triassic and Jurassic sections. However, gentle Jurassic rim basin tectonic activity has resulted in minor faulting compared to the adjacent rift. This has limited migration pathways from Triassic source to Jurassic reservoirs. The primary reservoir objectives are sandstones of the Triassic Upper and Lower Keraudren Formations.Although large structural traps are uncommon, there is considerable potential to host large hydrocarbon accumulations in stratigraphic traps. A giant prospect involving the onlap of the Triassic sequence has been identified in the eastern Bedout Sub-basin. Pursuit of this play should accelerate exploration in this sparsely drilled area.
DEPOSITIONAL SEQUENCE MODEL FOR THE POST-BARROW GROUP NEOCOMIAN SUCCESSION, BARROW AND EXMOUTH SUB-BASINS, WESTERN AUSTRALIA
Authors: Arditto Peter A.
Published: August 2017

Structural traps at the top 'Barrow Group' are the most successful oil exploration targets in the Barrow/Exmouth Sub-basins. However, a reinterpretation of recent exploration activities undertaken by BHP Petroleum Pty Ltd, combined with regional investigations on the Exmouth Plateau, has cast doubt on the validity of accepted stratigraphic nomenclature for the Neocomian succession. A more geologically rational subdivision of the upper part of the Neocomian succession into two discrete sequence stratigraphic units is proposed.Key seismic data from the Exmouth Plateau, tied into wells with good age control, have enabled precise recognition of the Intra-Valanginian Unconformity within the currently-defined Barrow Group. The Barrow Group (sensu stricto) is redefined in this paper as the Barrow Megasequence (restricted to a Berriasian age succession), comprising a rapid progradational phase, which was abruptly terminated by the Intra-Valanginian event.Local erosion of the Barrow Megasequence along the Novara Arch through an Early Valanginian uplift, during the ensuing Valanginian regional transgression, contributed to the development of a parasitic clastic wedge, previously referred to as the Upper Barrow Delta on the Exmouth Plateau and here named the Zeepaard Sequence, with a nominated section in Zeepaard-1. The Zeepaard sequence is terminated by a Top Valanginian unconformity, upon which a final deltaic clastic pulse was deposited as the Birdrong Sequence. Each successive clastic wedge had a more limited development, with the basinward progradation terminating well short of the underlying stratigraphic unit. The Birdrong Sequence was terminated by an Intra-Hauterivian unconformity upon which the highly glauconitic, thin, Mardie Greensand Member of the Muderong Sequence was developed.The Zeepaard Sequence and overlying Birdrong Sequence can be characterised using both seismic and well log character. Well data in particular has enabled detailed stratigraphic mapping of the Birdrong Sequence which is thin and generally not seismically resolvable across the Barrow Sub-basin. This paper presents a detailed sequence stratigraphic analysis of the Birdrong Sequence using well log data.