bluuebunny/crossref_metadata_2025 huggingface dataset:
BURIAL HISTORY OF THE EASTERN OFFICER BASIN, SOUTH AUSTRALIA
Authors: Moussavi-Harami R. , Gravestock D. I.
Published: August 2017

The intracratonic Officer Basin of central Australia was formed during the Neoproterozoic, approximately 820 m.y. ago. The eastern third of the Officer Basin is in South Australia and contains nine unconformity-bounded sequence sets (super-sequences), from Neoproterozoic to Tertiary in age. Burial history is interpreted from a series of diagrams generated from well data in structurally diverse settings. These enable comparison between the stable shelf and co-existing deep troughs. During the Neoproterozoic, subsidence in the north (Munyarai Trough) was much higher than in either the south (Giles area) or northeast (Manya Trough). This subsidence was related to tectonic as well as sediment loading. During the Cambrian, subsidence was much higher in the northeast and was probably due to tectonic and sediment loading (carbonates over siliciclastics). During the Early Ordovician, subsidence in the north created more accommodation space for the last marine transgression from the northeast. The high subsidence rate of Late Devonian rocks in the Munyarai Trough was probably related to rapid deposition of fine-grained siliciclastic sediments prior to the Alice Springs Orogeny. Rates of subsidence were very low during the Early Permian and Late Jurassic to Early Cretaceous, probably due to sediment loading rather than tectonic sinking. Potential Neoproterozoic source rocks were buried enough to reach initial maturity at the time of the terminal Proterozoic Petermann Ranges Orogeny. Early Cambrian potential source rocks in the Manya Trough were initially mature prior to the Delamerian Orogeny (Middle Cambrian) and fully mature on the Murnaroo Platform at the culmination of the Alice Springs Orogeny (Devonian).
THE EASTERN OTWAY BASIN WANGERRIP GROUP REVISITED USING AN INTEGRATED SEQUENCE STRATIGRAPHIC METHODOLOGY
Authors: Arditto P. A.
Published: August 2017

Recent exploration by BHP Petroleum in VIC/ P30 and VIC/P31, within the eastern Otway Basin, has contributed significantly to our understanding of the depositional history of the Paleocene to Eocene siliciclastic Wangerrip Group. The original lithostratigraphic definition of this group was based on outcrop description and subsequently applied to onshore and, more recently, offshore wells significantly basinward of the type sections. This resulted in confusing individual well lithostratigraphies which hampered traditional methods of subsurface correlation.A re-evaluation of the Wangerrip Group stratigraphy is presented based on the integration of outcrop, wireline well log, palynological and reflection seismic data. The Wangerrip Group can be divided into two distinct units based on seismic and well log character. A lower Paleocene succession rests conformably on the underlying Maastrichtian and older Sherbrook Group, and is separated from an overlying Late Paleocene to Eocene succession by a significant regional unconformity. This upper unit displays a highly progradational seismic character and is named here as the Wangerrip Megasequence.Regional seismic and well log correlation diagrams are used to illustrate a subdivision of the Wangerrip Megasequence into eight third-order sequences. This sequence stratigraphic subdivision of the Wangerrip Group is then used to construct a chronostratigraphic chart for the succession within this part of the Otway Basin.
CRAYFISH GROUP HYDROCARBONS—IMPLICATIONS FOR PALAEOENVIRONMENT OF EARLY CRETACEOUS RIFT FILL IN THE WESTERN OTWAY BASIN
Authors: Padley D. , McKirdy D. M. , Skinner J. E. , Summons R. E. , Morgan R. P.
Published: August 2017

Recent hydrocarbon discoveries in Early Cretaceous (pre-Aptian) reservoirs of the western Otway Basin offer encouragement to future petroleum exploration and also contain clues to the palaeoenvironments and early evolution of this rift basin. The Late Jurassic/Early Cretaceous Casterton Formation and the Early Cretaceous Crayfish Group have traditionally been regarded as fluvial and lacustrine deposits. Indeed, the source rock characteristics inferred from the geochemistry of the Katnook Field condensate and the oils from Wynn-1 and Sawpit-1 are those of siliciclastic freshwater facies. However, the biomarker assemblage of the Troas-1 condensate implies that its source beds were deposited in a marginal marine setting. Even more unexpected are the biomarker compositions of reservoir bitumens from Crayfish-Al and Zema-1 which provide evidence for the existence of saline to hypersaline palya lakes during the early rift phase of the Otway Basin.
SOME RECENT ADVANCES IN WIRELINE TESTING
Authors: Crocker H. , Hann J.H. , Hall P.B.
Published: August 2017

Modern wireline test tools pump formation fluids to the wellbore at surface-controlled rates. The flowing fluid characteristics of pressure, temperature, density, flow rate, conductivity and resistivity are monitored at the surface in real time. The wireline test is thus matched, by the operator, to meet the formation deliverability and sanding conditions. This new wireline formation testing technique has been successfully applied in wells in the Perth and Carnarvon Basins. The types of reservoirs tested in these wells include low permeability sands, high permeability sands, thin sands and a sand producing reservoir. Results show the tool operations to be flexible and that it may be operated to meet the testing requirements of specific formation characteristics.
THE EFFECTS OF DRILLING FLUID-SHALE INTERACTIONS ON WELLBORE STABILITY
Authors: Tan C.P , Zeynaly-Andabily E.M. , Rahman S.S.
Published: August 2017

Wellbore instability, experienced mainly in shale sections, has resulted in significant drilling delays and suspension of wells in major Australian petroleum basins. These instabilities may be induced by either in-situ stresses that are high relative to the strength of the formations or physico-chemical interactions of the drilling fluid with the shales.This paper describes fundamental concepts of mud pressure penetration and flow of water between the wellbore and formation due to their chemical potential difference, and associated mud support changes as the drilling fluid interacts with shales. Due to the low permeability of shales, the penetration of the drilling fluid filtrate would result in an increase in pore pressure over a considerable distance from the wellbore. This instability mechanism strongly depends on properties of the drilling fluid filtrate and pore fluid, and the rock material composition.In addition to mud pressure penetration, water would be induced to either flow into or out of the formation depending on the relative chemical potential of the drilling fluid and the formation. A more stable wellbore condition could be achieved by optimising the chemical potential of drilling fluids.Drilling fluid and shale properties required for the models, which are determined using analytical and laboratory techniques, are presented herein. The effects of the time-dependent mechanisms on wellbore stability are demonstrated for a polyacrylamide, an ester-based and an oil-based mud. The results demonstrate that a more effective mud support can be obtained by optimising the adhesion and viscosity of the drilling fluid filtrate, and chemical potential of the drilling fluid.
ACIDIZING KINETICS AND ITS APPLICATION TO PLANNING AND OPTIMISATION OF RESERVOIR STIMULATION AND FORMATION DAMAGE REMOVAL
Authors: Rahman S.S. , Nguyen D. , Wang G.Y.
Published: August 2017

Kinetic aspects of sandstone acidizing with mixtures of hydrofluoric (HF) and hydrochloric (HC1) acids have been studied experimentally using cores taken from a natural sandstone reservoir rock. The matrix reactivity and the resulting changes in porosity and permeability due to acid reactions were measured as a function of experimental conditions: (1) acid concentration, (2) injection rate and (3) temperature. The model parameters were correlated by a power law model. A numerical simulator was developed for linear flow to predict changes in core properties due to acidizing. Values from the simulator were verified by experimental results. This simulator was subsequently extended to radial flow, and therefore can be used to simulate field acid jobs of sandstone formations.
WHEN VENTURERS DISAGREE: STRATEGIES FOR RESOLVING CONFLICT
Authors: Standen M.L.
Published: August 2017

Disputes between joint venture participants continue to be a source of difficulty and inefficiency in the oil and gas industry. An overview is provided of the legal tools and techniques which may be helpful in minimising or resolving disputes, bearing in mind the impact of recent cases concerning fiduciary duties, the duties of nominee directors and developments in the area of alternative dispute resolution.Consideration is given to:Contractual techniques for minimising disputes.The obligations of joint venture participants:as fiduciaries; andas directors of joint venture vehicles.The impact of the Trade Practices Act.Techniques for alternative dispute resolution.
CAN RISK MANAGEMENT ADD VALUE?
Authors: Shimko D. C.
Published: August 2017

Proper risk management reduces risk, but does it necessarily add value for corporate shareholders? Modigliani and Miller argued in 1958 that the answer is 'no' in a perfect market setting. How risk management adds value in an imperfect markets setting is shown. In particular, the corporate risk management decision is linked to the leverage decision to measure the impact of risk reduction on shareholder value. A quantitative model is developed and is applied to five public commodity companies to calculate the value increase due to optimal risk management and leverage. Finally, the practical aspects of implementing a joint risk management and capital structure program are discussed.
DESIGN AND IMPLEMENTATION OF A SAFETY, HEALTH AND ENVIRONMENT MANAGEMENT SYSTEM IN BHP PETROLEUM
Authors: Mattes B.W. , Walters C.
Published: August 2017

BHP Petroleum Pty Ltd (BHPP) is subdivided, worldwide, into three 'regions'—Australia/Asia; Europe/Russia/Africa/Middle East; and Americas—each a self-contained, operating entity, each with its own system of management. The Australian/ Asian operations group within BHPP is implement­ing an integrated management system, of which the safety, occupational health and environmental ele­ments will form crucial components. The manage­ment system has been designed to provide manage­ment control of safety, health and environment issues for all of the BHPP producing operations in Australasia. The Safety, Health and Environment Department of BHPP provides a region-wide func­tion for Australasia, and the safety, health and environment portions of the management system, which the Department is helping to develop and implement, will document planned requirements at a number of levels: region-wide requirements for all departments (e.g. implementation of corporate policies, legislative compliance, emergency man­agement, auditing, permit-to-work, health promo­tion, incident investigation, environmental approv­als, etc), requirements specific to the Operations Department (e.g. safety/environmental auditing of plants and facilities, monitoring of oil spills/green­house gas emissions), and requirements specific to operational sites within the Operations Depart­ment. Responsibility for development, implemen­tation, and maintenance of the management sys­tem, and compliance with its provisions, rests with line management—a logical extension of the ac­countability and responsibility for safety, health and environment matters that rests squarely on the shoulders of all line managers within BHPP. The Safety, Health and Environment Department pro­vides expert advice, document control, training and auditing expertise, and offers a pool of experts available for participation in projects on a consulta­tive basis. For contractor management, the BHPP system mandates intensive scrutiny of contractor safety, health and environmental performance and the systems that the contractor has in place to manage that performance, beginning at the stage of contract prequalification. Failure to meet the mini­mum standards set by BHPP will disqualify a con­tractor from contract tendering unless and until remedial action is taken. The ultimate aim of the BHPP system is a level of safety, health and envi­ronmental performance which leads the world—no injuries, no workplace health or hygiene problems and no adverse effect on the environment.
ENVIRONMENTAL LAW REGIMES—PETROLEUM OPERATIONS IN AUSTRALIA'S OFFSHORE AREAS
Authors: Cole D.A.
Published: August 2017

Increasing petroleum activity in Australia's off­shore areas is heightening industry, government and community awareness of the potential impact of these operations on marine ecosystems and coastal environments.The Offshore Constitutional Settlement of the late 1970s has resolved the issue of allocation of governmental rights and powers over the resources of the sea and the seabed. However, the application of environmental laws to those areas remains largely untested. A complex web of legislation—State, Ter­ritory and Commonwealth—may apply to proposed and on-going petroleum activities.The Commonwealth Government has substantial power to intervene to protect environmentally sen­sitive areas whether they are within areas of the sea over which that government or the states or the Northern Territory have primary jurisdiction. De­spite the recent Intergovernmental Agreement on the Environment, substantial ultimate power re­sides with the Commonwealth to protect the envi­ronment, particularly through the use of the exter­nal affairs power. The politically fluid nature of environmental management in offshore areas adds an important dimension to the commercial risk assessment process for the petroleum industry.
COMMAND PETROLEUM—HOME AND AWAY
Authors: Doran R.J.P.
Published: August 2017

Recent overseas expansion has enabled Command to acquire new reserves cost effectively and gain access to world class exploration plays, but the company still calls Australia home. The evolution of the company's overseas expansion strategy can be directly attributed to specific and readily identifiable corporate characteristics. Through overseas expansion, the company has added value faster and more cost efficiently than would have been possible if its activities had been confined to Australia. Overseas expansion should not, however, be regarded as a growth panacea for other Australian oil companies. A company can only succeed by playing to its corporate strengths and not every company is genetically suited to overseas exploration.
REPLACING BASS STRAIT—BHP PETROLEUM'S GLOBAL QUEST, 1970 TO 1994
Authors: Clifford A. C.
Published: August 2017

Twenty five years ago, after Bass Strait production had commenced in 1969, BHP Petroleum (BHP) began its global quest for a new Bass Strait. The first stepouts were close to home and opportunistic and the company preferred the role of non-operator, not having the necessary offshore operating expertise at that time. BHP had been driven overseas in its search by the punitive tax regime and limited prospectivity for another Bass Strait at home.The first significant milestone was 1981, after the North West Shelf project go-ahead, with the company desiring to operate and expand overseas. With the discovery of petroleum in the Timor Sea, BHP had developed innovative engineering capabilities which were later enhanced through the acquisition of Hamilton Oil (1991). Acquisitions were considered important for the company's growth from the early 1980s onward and were highlighted in BHPP's first major strategic review in 1985 together with the need to undertake global basin studies.As the 1980s progressed, there was a rapid expansion of staff due largely to acquisitions. BHP consolidated its US position with two acquisitions, then entered the downstream oil sector via the PRI (Hawaii) acquisition in 1989. The Hamilton acquisition helped to enhance the company's global reputation as a low cost, fast track offshore developer, a capability which helped capture the Dai Hung oilfield development opportunity, offshore Vietnam.A major strategic review in 1992 identified opportunities in downstream gas and power and multiple entry points to the energy value chain are now being targeted. In addition, a more focussed approach to exploration is being employed.
NEW GAS DISCOVERIES IN THE NORTHERN COOPER BASIN
Authors: Wecker H.R.B. , Ziolkowski V. , Powis G.D.
Published: August 2017

Over the last two decades, minimal gas exploration was undertaken in the northeastern Cooper Basin. It was viewed the area held negligible gas potential due to the perceived absence of conventional anticlinal traps and the marginal reservoir quality of the Permian sandstones.With the award of permit ATP 549P to Mount Isa Mines Limited in mid-1993, available seismic and well data were reviewed to highlight potential fault-controlled traps in the region and to define areas likely to contain more favourable reservoir sandstones. A vibroseis seismic survey provided the initial prospects and leads inventory upon which the 1994 drilling program was based. Four prospects were tested resulting in three gas discoveries.Based on these encouraging results, an additional phase of seismic acquisition was completed to increase the prospect inventory. Thereafter, a five well program was undertaken. Whilst the two appraisal wells were successful, three wildcat wells failed due to ineffective trapping.A completion and testing program has been initiated to further evaluate the field discoveries.From an exploration viewpoint, the recognition of a consistently productive sandstone in the basal Toolachee Formation within a broad fairway across the eastern ATP 549P permit block was a significant result which has important implications for future activities. Within the fairway, gas flows varying from 0.4 MMcfd up to 6.0 MMcfd were measured on openhole tests. In addition, substantial gas volumes in low permeability sandstones within the Patchawarra Formation have been defined.These discoveries, coupled with the number of prospects and leads and the proposed gas pipeline to Mount Isa and to southeast Queensland markets, provide strong impetus to the continued evaluation of this northern extension of the Cooper Basin gas province.
THE INTEGRATED DEVELOPMENT OF GILMORE FIELD AND AN INDEPENDENT POWER PLANT
Authors: Boer R.A. de
Published: August 2017

Thirty one years after its discovery in Queensland's remote Adavale Basin, the Gilmore Field has been put into commercial production, supplying fuel gas to Australia's first independent power plant wholly dedicated to feed a state electricity grid.Gilmore Field is located in PL-65 in Central Queensland. It is a deep, high pressure gasfield which produces dry gas. The gas is primarily methane with up to 21 per cent nitrogen. Three of the five wells in the field currently produce into gas gathering and processing facilities. Gas is piped 240 km to Barcaldine to fuel a Frame-6 gas turbine, generating 37 MW in a peak loading power-station, which operates 14 hours per day, 5 days per week. Further development in Gilmore Field is planned.Numerous development plans have been proposed for Gilmore Field, since its discovery in 1964, but none were successful due to uncertainties on reserves and remoteness. The recent relaxation of state control on utilities and an increase in local demand for electricity created a niche for development of the field.Energy Equity Corporation Ltd (EEC) was responsible for the entire development project which consists of gas gathering and field facilities, a 240 km gas pipeline, power plant and the electricity supply contract. This allowed various aspects of the project to be interactively designed to suit the field's capacity and was an important part of the successful development.As part of the development, the geology was re-evaluated and the field was extensively tested. This resulted in a clearer understanding of the reservoir parameters and a revision of the Devonian stratigraphy of the Adavale Basin. The main producing horizon is the Lissoy Sandstone, a transgressive marine sequence deposited as a strandline over alluvial sandstones of the Log Creek Formation. Reservoir quality is controlled by facies and diagenesis. The productive reservoir consists of near-shore sandstone facies which have developed inter-granular porosity through dissolution of early marine cements. Other facies of the Lissoy Sandstone and the Log Creek Formation are host to low deliverability reserves.
BAYU/UNDAN GAS-CONDENSATE DISCOVERY: WESTERN TIMOR GAP ZONE OF COOPERATION, AREA A.
Authors: Brooks D. M. , Goody A. K. , O'Reilly J. B. , McCarty K. L.
Published: August 2017

The Bayu/Undan Gas-Condensate Field straddles the boundary between the ZOCA 91-12 and ZOCA 91-13 PSC areas, within the Timor Gap Zone of Cooperation Area A (ZOCA). The field is located approximately 450 km north­west of Darwin, NT, and 350 km east-southeast of Kupang, Timor. The closure is the culmination of the Flamingo High, a major structural element within the northern Bonaparte Basin. This structure has been viewed as having significant hydrocarbon potential since Flamingo-1 recovered gas from Berriasian sandstones in 1971.The discovery well, Bayu-1, was drilled by the ZOCA 91-13 contract operator, Phillips Petroleum Company ZOC, in early 1995. Bayu-1 intersected a gross 155m gas-condensate column within Middle Jurassic sandstones at a depth of 2,954.5 mSS. The ZOCA 91-12 joint venture then drilled Undan-1,10 km northwest of Bayu-1, on a separate culmination within the closure defined by the Bayu-1 gas-water contact. Undan-1 and subsequent wells have confirmed the existence of one large gas-conden­sate field, with a most likely areal extent of over 160 km2.The sandstone reservoir consists of late Oxfordian to Callovian shallow marine, deltaic to shoreface, coarsen­ing upward parasequences, overlying Callovian to Bajocian marginal marine to coastal plain sediments. The trap is an east-west oriented horst block bounded by en-echelon normal faults to the north and south, with dip closure to the east and west. Seal is provided by Tithonian to Barremian marine claystones. A likely hydrocarbon source is contained within the Barremian to Callovian interval, some of which are mature for condensate and wet gas expulsion in the southern Sahul Syncline and Malita Graben.
THE COMBINED APPLICATION AND UTILISATION OF CMR™ AND FMI™ WIRELINE TECHNOLOGY IN WONNICH-I
Authors: Roestenburg J.W.
Published: August 2017

Wonnich, a new gas and oil discovery was drilled in July 1995 within exploration permit TP/8 Part 1 in the Barrow Sub-3asin. The well was logged using emerging wireline technology which resulted m significant im­provements in understanding the quality of reservoir rocks, their genesis and post depositiunal alterations. Both the Combinable Magnetic Resonance Imaging Tool (CMR™) and the Formation Micro-Imager (FMI™) data were acquired in the 216 mm hole section of the well. The interval between 2.575 and 2,525 m. which forms the basis of this technology review, comprises an aquifer sandstone which was logged with the CMR tool to inves­tigate the pore size and distribution and to provide a comparison between the CMR porosity and standard porosity derivations. The CMR data presented in this paper was p-ocessed by Schlumberger using the stan­dard sandstone settings. The high resolution, density derived porosity and the CMR porosity showed good agreement in both magnitude and vertical resolution. The aquifer sandstones reached a maximum of 18 per cent porosity with a CMR permeability maximum of 400md between 2,544-2,551 m. The T2 relaxation times distribution in sands, occurs between 33 and 250 ms with the peak and mean coinciding at 100ms. Several shale intervals show T2 attenuation due to hole washout. Utilising both the FMI azimuthal images and the CMR permeability curve it was established that some of the permeability barriers shown by the CMR and 'regular' open hole logs are in fact nodular formation components, rather than beds. These would thus not impact fluid flow and completion design. Further image analysis within the aquifer sands shows that the palaeocurrent direction is northwest, with a southeasterly sediment provenance. The larger scale process signatures within the lower sand are replaced by friction dominated and low energy pro­cesses towards the upper portion of the sand. This fining upwards profile is reflected not only in the GR logs but also in the pore size reductions shown by the CMR T2 relaxation profiles extending the application of these technologies to depositional environment analysis and grain size distribution. Post depositional influences in­clude siderite and clay diagenesis and fracturing associ­ated with aquifer seals.
ASSESSMENT OF THE SEAL POTENTIAL OF TERTIARY CARBONATES, DUNTROON BASIN, SOUTH AUSTRALIA
Authors: Messent B. E. J. , Wilson C. , Flynn K.
Published: August 2017

The seal potential of the Wilson Bluff and Nullarbor Limestone Formations was assessed over high-graded Pidinga Formation leads of the Duntroon Basin that contain significant hydrocarbon potential. The work quantified the risk associated with these plays. Regional geological knowledge was integrated with the results of special core analysis and petrography to address the 3 critical aspects of seal quality: seal capacity, seal geometry and seal integrity.This work established a clear relationship between seal potential and lithofacies, namely, the higher the clastic content, the better the seal potential. More specifically, in the vicinity of the Tertiary channel system and clastic axis, the seal risk for the Wilson Bluff Formation carbonates is considered to be relatively low, since it contains a significant argillaceous component. A maximum oil column of up to 650 m could be contained, with a more likely column of approximately 20–75 m. With increasing distance from the channel system, there is a decrease in argillaceous content and an associated increase in seal risk, the size of the oil column that could be contained varying from 2 m to 300 m, the more likely being 2–20 m. The Nullarbor Limestone is considered to be a relatively poor seal as a result of extensive development of secondary porosity during diagenesis. A maximum oil column of 160 m could be contained, the more likely column being approximately 5–30 m.
UNDERSTANDING EFFECTIVE AND TOTAL POROSITY: THE KEY TO OPTIMISING MINERALOGICAL PETROPHYSICAL EVALUATIONS
Authors: Penney R. K. , Looi S.Y.
Published: August 2017

Use of petrophysical evaluation models that rely on predicting mineral composition of reservoir rocks is becoming more prevalent in the oil industry. Evaluation tools such as Schlumberger's Elan or Mincom's Geolog/Multimin allow prediction of variability in reservoir composition and petrophysical parameters. These are particularly useful in cases where assuming constant lithology and petrophysical parameters can result in significant variation in well evaluation, hydrocarbons in place estimates and volumetric reserves.Mineralogical evaluations have historically been questioned in cases where evaluated effective porosity differs significantly from core total porosity. Effort has been made over the last year to obtain maximum value out of these tools by providing all data as input to an integrated evaluation using total porosity. The key feature is incorporating all possible core data for calibration purposes, including:using all core total porosity, permeability and capillary pressure data, where available, to calibrate modelsusing petrological data to obtain mineral-by-mineral calibration of rock compositionoverlaying a regional total porosity curve in the absence of core data to provide a quality control on evaluated total porosity.The success of such approaches is demonstrated in an offshore WA greensand and an Eromanga shaly sand. These methods are now used on a routine basis for detailed field studies and hold the promise of both permeability evaluation and improved evaluation of wells with restricted logging suites.
THE AGE OF NEOPROTEROZOIC-PALAEOZOIC SEDIMENTS WITHIN THE OFFICER BASIN OF THE CENTRALIAN SUPER-BASIN CAN BE CONSTRAINED BY MAJOR SEQUENCE-BOUNDING UNCONFORMITIES
Authors: Perincek D.
Published: August 2017

The age of stratigraphic units within the Neoproterozoic of the Centralian Super-Basin caii be constrained by using major sequence bounding unconformities. The Officer Basin is redefined to include the Yeneena, Karara, and Savory Basins.Correlation of structural and stratigraphic relationships apparent in surface geological maps to seismic and borehole data leads to the conclusion that the Petermann Ranges Orogeny and the Paterson Orogeny are the same event. The name Petermann Ranges Orogeny has been used extensively in the Centralian Super-basin. It is considered for this publication, to be correlated with and hence to replace the term 'Paterson Orogeny'. This Tectonic event occurred at 540 to 570 Ma and postdated deposition of the Boondawari, Lupton, Pertatataka and Julie Formations and Rodda Beds. These Formations are correlated as part of the same depositional episode; which is separated from the younger Babbagoola Formation and lateral equivalents by a regional unconformity resulting from the Petermann Ranges Orogeny. The Babbagoola Formation is correlated with the Tchukardine and McFadden Formations of the Savory Sub-basin and the Relief Sandstone of the eastern Officer Basin.The Petermann Ranges Orogeny produced a central uplift which includes the Rudall and Musgrave Complexes, forming the north-eastern boundary of the Officer Basin. The Musgrave Complex advanced further south in comparison to the Rudall Complex, with accommodation along numerous north and northeast trending faults. Initial movement along these faults probably started as early as Cambrian and was repeatedly reactivated till post Miocene.Extensive reverse faulting, folding and initiation of diapiric movement of the Upper Proterozoic section began in late Neoproterozoic to Early Cambrian. Reactivation of diapiric movement and folding occurred after and before extrusion of the Table Hill Volcanics. Salt movement continued during the post-Permian and post-Early Cretaceous periods. The evolution of salt structures in the basin from Neoproterozoic to post-Cretaceous provides many different aged traps for migrating hydrocarbons.
MULTIVARIATE OPTIMISATION OF HYDRAULIC FRACTURE DESIGN
Authors: Yang Z. , Crosby D.G. , Khurana A.K.
Published: August 2017

This paper presents a detailed description of a true multivariate optimisation routine for the design of hydraulic fractures. Using the Sequential Unconstrained Minimisation Technique, the optimisation routine intelligently searches for the optimum combination of operator-controllable hydraulic fracture treatment parameters, as opposed to existing simple iterative schemes. Net Present Value (NPV) was used as a measure of the economic impact of hydraulic fracture design on incremental reservoir production revenue. The effects of individual treatment parameters on incremental NPV were investigated for a hypothetical well. The results showed that there was an optimum value for each of the treatment parameters: injection period, injection rate and proppant concentration. For the same hypothetical well, contours of incremental NPV vs two fracture treatment parameters (injection period/injection rate and injection period/proppant concentration) were also constructed. These contours were smooth and continuous and did not show multiple extreme value points. These observations imply that there should be no obvious barriers to the estimation of the optimal hydraulic fracture design using the optimisation routine. Indeed, through visual inspection of the contours in the case of 2 treatment parameters, the optimisation routine consistently arrived at the optimum solution for a given set of inputs. The optimisation routine was extended to 3 treatment parameters (injection period, rate, and proppant concentration) and again consistently arrived at the same optimum solution with different starting positions. The optimisation routine can be extended to any number of operator controllable treatment parameters.
PREDICTION OF MICROANNULUS BEHIND CASINGS DUE TO BALLOONING EFFECT—A KEY PROBLEM IN GAS WELLS
Authors: Akgun F. , Kuru E. , Rahman S.S.
Published: August 2017

Casings are pressurised for various reasons during cementing. This pressure inflates casing just like a balloon. As the cement sets and the pressure is released, the elastically deformed casing tends to come back to its original shape leaving behind a microannulus at the cement casing bond. This annular space between cement and casing is too narrow to allow communication of liquids, nevertheless it is permeable enough for gas to flow through. An 8-node, quadrilateral, thin shell finite element model with plane stress and plate flexure capabilities has been used to study the formation of a microannulus during cementing of gas wells. The results of this study suggest that formation of a microannulus is a function of differential pressure across the wall of the casing, steel properties, casing dimensions and cementing temperature.
TAXATION TREATMENT OF REHABILITATION AND ENVIRONMENTAL EXPENDITURE
Authors: Burrell C.T.
Published: August 2017

In recent times, the political impetus gathered by the greater public environmental awareness has resulted in an explosion in the volume and complexity of mandatory environmental standards imposed on almost all industry, but particularly on mining and petroleum operations.1 Pressure exerted by the public (including shareholders) requires that companies not only take their mandatory requirements seriously, but that they also voluntarily assume certain environmental responsibilities. These pressures have and will result in higher levels of expenditure for many companies in areas not previously incurred, highlighting the need for adequate taxation relief to be provided.The paper examines firstly the deductibility of rehabilitation and environmental expenditure under Section 51(1) of the Act. Further, it examines specific provisions within the Act available to all companies which relate to expenditure on environmental impact studies, or for the protection of the environment. The paper also examines rehabilitation provisions which relate specifically to the mining industry. The discussion includes consideration of recent leading cases such as the MIM Case and the AMC Case.While the paper looks at the deductibility of such costs generally, it is directed at the mining and petroleum industries and seeks to identify practical examples that would be encountered by petroleum explorers. The paper also seeks to identify weaknesses within the current legislative framework that adversely affect companies carrying out rehabilitation and other environmental activities.
TIMOR GAP—THE INDONESIAN TAX ISSUES
Authors: Huray P. G. Le
Published: August 2017

This paper focuses on the Indonesian taxation issues relevant to activities undertaken in Area A of the Zone of Cooperation in the Timor Gap by non-Indonesian (foreign) contractors and service providers. This area is controlled equally by Indonesia and Australia through the Timor Gap Treaty (Treaty) arrangements.The broad framework of how taxes will be applied to Area A activities to achieve an equal sharing between Australia and Indonesia has been agreed through the Treaty, with the administration being left to the Tax Authorities of each country.On the Indonesian side, no regulations have yet issued to provide specific guidance on, inter alia:whether the application of Indonesia taxes to foreign contractors will follow that adopted for the Indonesian oil and gas industry;the tax treatment of foreign service providers operating in Area A; andhow the agreed modifications in the Treaty to reflect shared taxing arrangements will be observed in the application of Indonesia's Taxation Laws.The absence of any guidance has created much uncertainty among foreign contractors and their service providers undertaking activities in Area A. At the time of writing, we understand from a senior officer within the Indonesian Taxation Office (ITO) that this issue is high on their agenda and regulation(s) will be forthcoming within the near future.
FRONTIERS OF ENVIRONMENTAL REGULATION-ENVIRONMENTAL MANAGEMENT SYSTEMS: A REGULATOR'S PERSPECTIVE
Authors: Stone M. J.
Published: August 2017

Leading edge companies throughout the world have embraced management systems to achieve optimal sustainable performance in the ever changing business environment of the 1990s.Given that the natural environment and environmental performance have become one of the major issues affecting organisations, the need for integrating environmental management with all the other components of an organisation's overall management approach is now widely recognised.Systems interface best with systems. For environmental management to interface effectively with an organisation's other management systems, a systems approach to environmental management would seem the best. The release in November last year of the draft international standards (ISO 14000 series) on environmental management systems (EMS) has provided organisations with an internationally recognised means for this to occur and provided an additional benchmarking tool.It follows that environmental regulatory systems are required to enable regulators to effectively interface with company EMSs. Regulatory theory suggests that outcomes-based approaches are preferable to prescriptive approaches. Those parts of EMS standards which detail the requirements for particular system elements could provide the nexus for the company, regulator and community in future co-regulatory frameworks.These EMS standards refer to both regulators and the community as 'Interested Parties' being either 'concerned with or affected by the environmental performance of an organisation'.The Interim EMS specifications standard, released in Australia and New Zealand as AS/NZS ISO 14001(Int):1995 refers to 'Interested Parties' in only two EMS elements, 'Objectives and Targets' and 'Communication'. It is here that there are potential benefits and opportunities for companies, regulators and the community to cooperate in the emerging climate of these new international standards.
THE CREATION AND FLOTATION OF NOVUS PETROLEUM LTD
Authors: Williams R.C.
Published: August 2017

Novus Petroleum Ltd listed on the Australian Stock Exchange on 24 May 1995 having raised $157.5 million of equity. It was the largest initial public offering (IPO) of an oil company ever undertaken in Australia, and the third largest equity-raising on the Australian market during financial year 1994-5.The creation of Novus involved the creation of a team of professional advisers comprising ANZ McCaughan (broker), Indosuez Australia (financial adviser), Ernst and Young (accounting and taxation adviser), Phillips Fox (legal adviser) and Fern Consultants (technical adviser). During the period from mid 1994 to May 1995, the team identified and procured a portfolio of producing and exploration assets (including shares in over 30 oil and gas fields); negotiated sale and purchase, underwriting, loan and other necessary agreements; wrote and issued a prospectus and performed the necessary due diligence and other processes involved with a public equity offering; and marketed the stock in the new company globally.The success of the IPO is attributed to having a very clear business focus and strategy, a diverse portfolio of quality assets, a strong and experienced management team, good earnings arithmetic and a strong balance sheet. Delivery of the success is attributed to the commitment and enthusiasm of the professional team involved with the float process.
COMMERCIAL DEVELOPMENTS OF 1995
Authors: McHolick W.R.
Published: August 2017

The year 1995 witnessed the largest growth in world oil demand in recent history. This growth was driven principally by increased consumption in Asia. Despite this increased demand average oil prices rose only marginally due to both excess production capacity within OPEC and the expectation of the return of the Iraqis to the world oil market. Oil prices are unlikely to improve over the long term since the over-supply of crude is expected to persist well into the next century.In Australia there was an increased reliance on imported oil, as consumption rose in response to an expanding economy whilst domestic liquids production continued to decline. The contribution of the Australian upstream industry continued to shift towards Western Australia as production from the Carnarvon Basin rose, whilst Bass Strait declined. Gas production rose for the year although the LNG facilities on the Burrup Peninsula are now working at full capacity. Further growth in LNG sales will require facilities expansion and such plans were well advanced over the course of last year.The profitability of the upstream oil and gas sector continued to be poor, despite the positive signs within the West Australian market. This situation is unlikely to change in the short term as the over-supply of crude is expected to hold down oil prices. The long term viability of the E&P industry in Australia may well depend on further modification of the current fiscal regime.
RESERVOIR CHARACTERISATION OF THE MOORARI/WOOLKINA FIELD COMPLEX, COOPER BASIN
Authors: Seggie R. J.
Published: August 2017

The Tirrawarra Sandstone oil accumulation at the Moorari/Woolkina Field complex in the Cooper Basin, Central Australia has been under miscible gas flood EOR since 1984. A facies-based reservoir characterisation study of the field was undertaken to help explain unpredicted field performance and to provide a reliable model on which to base any future field development and necessary engineering studies prior to blow down.The reservoir is dominated by the interaction of fluvial braid-plain and glacio-lacustrine shoreface processes in a braid-delta setting. It comprises five basic facies from which eleven sub-facies are identified, eight containing oil bearing reservoir. An extensive field wide lacustrine mudstone acts as a vertical barrier and divides the reservoir into two gross sand units. The individual sub-facies were petrographically and petrophysically characterised and mapped in detail to provide a model of the field architecture, within which the residency of the original and remaining oil-in-place was determined.A substantial increase in OOIP explained the better than predicted performance from the EOR pattern and highlighted the field flanks for assessment for incremental development. This was confirmed by the engineering data review which also revealed that the poor structurally low wells were affected by relative permeability effects. As a result of this study, plans for incremental field development are in progress with the goal of increasing reserves and production.
AN INTEGRATED APPROACH TO THE STUDY OF THE EARLY TRIASSIC REWAN GROUP, BOWEN BASIN
Authors: Grech P.V. , Dyson I.A.
Published: August 2017

This study of the Early Triassic Rewan Group in the Bowen Basin was an integrated approach using seismic stratigraphic principles with outcrop, wireline log, bios- tratigraphy and core data. It resulted in a coherent and useable stratigraphic framework that assisted in defining facies and potential reservoirs below seismic resolution within the Rewan Group. The Rewan Group consists of the Sagittarius Sandstone and Arcadia Formation. Depositional systems of the Sagittarius Sandstone and Arcadia Formation were affected by major tectonic and climatic changes. Each formation is marked at its base by a third-order sequence boundary. The Sagittarius Sandstone is overall regressive and was deposited in a domi- nantly lacustrine environment. The base of the overlying Arcadia Formation is marked by the Brumby Sandstone Member. It was deposited in a fluvially dominated shoreface setting. Red beds of fluvial origin in the Arcadia Formation are characterised by overbank fines and lenticular channel sandstone. High-frequency incised valley fills occur in the uppermost Arcadia Formation. The Arcadia Formation is in turn erosively overlain by pebbly sandstone of the Clematis Group. Sandstone-filled incised valleys at the base of the Sagittarius Sandstone and in the upper Arcadia Formation offer the best reservoir potential in the Rewan Group.
SALT MIGRATION AND SUBTLE STRUCTURES: MODELLING OF THE PETREL SUB-BASIN, NORTHWEST AUSTRALIA.
Authors: Lemon N.M. , Barnes C.R.
Published: August 2017

Salt diapirs have been well documented in the Petrel Sub-basin of the Bonaparte Basin, offshore northwestern Australia, indicating that mobile salt exists at depth. G raphi- cal manipulation of geometric shapes on paper and analogue sandbox modelling were used to investigate the nature of structures produced in the sub-basin. The models rely on assumptions about the shapes developed by the moving salt, the timing of the movement and use the principle of vertical shear to adjust the accommodation space created by simple subsidence. The slug-like shape of the mobile salt wedges was adapted from the shapes imaged in the Gulf of Mexico by recent 3D seismic surveys.A simple graphic model of lateral salt migration replicates structures seen on a seismic panel from the Petrel Sub-basin in which wedges of sediment prograde from the basin centre to the basin margin. A more complex graphical model accounts for simple basin subsidence and salt migration shows many of the unusual features seen along the AGSO regional seismic Line 100/03. A sandbox model replicated the same features, including the broad dome of the Petrel structure, the sharper anticline around Tern, the depocentre northeast of Petrel, the smaller depocentre to the southeast and a number of small step-like structures. All these features are unusual as the amplitude diminishes upwards and downwards with no apparent basement control.The striking similarity of the models to the structures imaged by seismic suggests that salt has moved laterally, largely confined within the original evaporite stratigraphic level, taking on a slug-like shape, with an enlarged head and thin tail.This work gives an alternative explanation to the development of structures previously ascribed to compression, although the role of compression is not entirely discounted. The involvement of salt in the formation of large, but subtle structures such as the Petrel gas field, implies a longer history for the structures with influence on hydrocarbon migration, entrapment and the distribution of reservoir facies.
HYDRODYNAMICS AND FAULT SEAL ASSESSMENT IN THE VULCAN SUB-BASIN, TIMOR SEA
Authors: Yassir NL , Otto C. J.
Published: August 2017

The study of hydrodynamics sheds light on the current day fluid flow regime of traps of different integrity and on the mechanisms leading to seal breach. It also provides insights into potential migration pathways and zones of secondary hydrocarbon accumulation. This is a preliminary hydrodynamic investigation carried out on a few selected wells in the Vulcan Sub-basin from high, moderate and low integrity traps, referred to here as HIT, MIT and LIT respectively (after O'Brien et al, 1996). The fields sampled include East Swan (LIT), Skua and Jabiru (MIT) and Montara and Oliver (HIT). The findings of this study suggest a trend between trap type and current day fluid flow. The best result was obtained for Skua-2, where pressure testing was conducted over the bounding fault for the field, indicating high integrity. Some wells showed upward head gradients, such as East Swan-2; others showed a low or no vertical gradient, such as Jabiru-1 A,−2, −3, −10 and Oliver-1. There was general agreement between the flow direction and the conductivity of the faults, as indicated by mud loss data. Preliminary potentiometric surface mapping of Jabiru indicated lateral flow, controlled by production, and hydraulic communication within the faulted reservoir. Wellbore hydrodynamics and potentiometric surface mapping of the reservoir heads on a regional scale promise to give indications of major structural controls on flow as well as secondary migration pathways.