bluuebunny/crossref_metadata_2025 huggingface dataset:
IMPROVING RECOVERY IN A THIN OIL COLUMN RESERVOIR—TUNA M–1 RESERVOIR EXPERIENCE IN THE GIPPSLAND BASIN, SOUTHEAST AUSTRALIA
Authors: Santamaria C. , Fish R.
Published: August 2017

The Tuna M–1 reservoir was developed in 1997 from both the new West Tuna platform and the existing Tuna A platform in the Gippsland Basin. The M–1 reservoir is contained within an anticlinal closure with an approximate gross hydrocarbon column of 85 metres. The oil column was originally 12 m thick and is supported by a large gas cap and a strong flank aquifer.Performance from the M–1 reservoir has been good, due to excellent reservoir properties. The combination of conventional and geo-steered horizontal wells has performed well with recovery efficiencies of 70% observed in many parts of the field. Lower than expected performance from the northwestern edge of the oil rim was, however, a significant anomaly, with recovery efficiencies 10% lower than from comparable rock in the southern and eastern parts of the field. The underlying cause of this lower performance was believed to be the result of an anisotropic aquifer response allowing greater pressure support along the northwestern flank of the fieldA re-entry well was drilled from a watered out horizontal well on the Tuna A platform in December 2000. This well was drilled as an oil production opportunity and as a key surveillance data point for the northwestern flank of the field. Results led to further surveillance including contact monitoring and production logging in horizontal wells. In addition to this, simulations were updated to reflect actual performance and surveillance data. Subsequent analysis supported development of a work program for new M–1 drainage points, including additional drill wells and the conversion of existing, watered out horizontal wells to conventional wells. The M–1 redevelopment work has been highly successful with production rates increasing by about 20,000 barrels per day in the first nine months of the program.
DEVELOPMENT OF THE TARANAKI BASIN AND COMPARISONS WITH THE GIPPSLAND BASIN: IMPLICATIONS FOR DEEPWATER EXPLORATION
Authors: Uruski C. , Baillie P. , Stagpoole V.
Published: August 2017

Exploration of the Taranaki Basin entered a new phase in 2001 with Astrolabe, a 6,200 km high-quality 2D seismic survey acquired by TGS-NOPEC that has outlined a large depocentre containing up to 10 km of sedimentary fill. This new data has extended the previously-known Taranaki Basin into deeper water beyond the shelf edge. Subsequently, the New Zealand Government released an area of 42,000 km2 for competitive bidding to close in September 2003.Sequence analysis shows that a major deltaic system, comparable to the Golden Beach and Emperor subgroups of the Gippsland Basin, built into a restricted seaway during the Late Cretaceous and culminated with deposition of the Rakopi Formation coal measure succession. The Rakopi Formation covers an area of at least 15,000 km2 of the study area and was followed by a transgression that continued until the Miocene.Minor Eocene folding created broad structures with potential to trap large volumes of petroleum. Other potential trapping structures include drape across Cretaceous rift blocks and turbidite mounds of Miocene age.Modelling shows that much of the Early Cretaceous delta is thermally mature and should be expelling petroleum today. Reservoir facies are present at many horizons, but the primary target is expected to be sandstones of the Rakopi Formation coal measures.Many analogies can be drawn between the Taranaki and Gippsland basins. The deepwater Taranaki basin appears to be equivalent, however, to the offshore, oilprone part of Gippsland while the nearshore Taranaki and Great South basins together form an analogy for the more gas-prone nearshore part of Gippsland.
GIPPSLAND—NEW POTENTIAL FROM A MATURE BASIN
Authors: Heath N.M.
Published: August 2017

It is now 39 years since the first gas was discovered in Bass Strait’s Gippsland Basin. Advances in exploration and production technology mean that today Australia’s longest producing offshore basin is also one of Australia’s most prospective. Gippsland is now producing around 160,000 barrels of crude and 570 million cubic feet of gas per day. To date it has produced more than 3.5 billion barrels of oil and 5 trillion cubic feet of gas and the value of the infrastructure in place is estimated to be around A$16 billion.Australia’s evolving energy market means that gas demand continues to grow. Following the re-structuring of energy markets in southeastern Australia and the installation of new pipeline infrastructure, Gippsland gas now flows to Victoria, NSW, Tasmania and will supply into South Australia from 2004. To meet this growing demand the Esso/BHPBilliton joint venture partners are investing heavily and utilising a vast array of 3D exploration technology to unlock new opportunities. In 2002 they conducted the largest 3D survey ever undertaken in Bass Strait and expect to conduct another in early 2003. A program of exploration drilling is expected to commence in late 2003. With expanded market opportunities and a gas resource base of more than 5 trillion cubic feet, the future looks bright for Gippsland.
RESERVOIR GEOMETRY OF FLUVIAL DISTRIBUTARY CHANNELS—IMPLICATIONS FOR NORTHWEST SHELF, AUSTRALIA, DELTAIC SUCCESSIONS
Authors: Payenberg T.H.D. , Lang S.C.
Published: August 2017

The exploration and development of stratigraphically trapped hydrocarbons requires detailed knowledge of the morphologies and reservoir characteristics of the stratigraphic body. Fluvial distributary channels are important exploration targets because they are typically isolated reservoirs, laterally and vertically sealed by delta plain and abandoned channel mudstone, and thus form excellent stratigraphic traps. The morphology and reservoir characteristics of fluvial distributary channels have been confused with fluvial channels in the past. Knowing the characteristics of fluvial distributary channels and their difference from fluvial channels is the key to the successful exploration and development of distributary channel reservoirs.Fluvial distributary channels, formed by mixed-load systems, are commonly rectilinear channel segments found only on the delta plain between the head of passes and the depositional mouthbars. While fluvial channel reservoirs are mainly sandstone deposits of meander pointbars or braided sheets, fluvial distributary channel reservoirs are typically elongated sandy channel sidebars attached to morphologically rectilinear channel walls. The sidebars form by both lateral and downstream accretion resulting from flow in a confined, but lowsinuosity thalweg, which may be filled with organic mud following channel abandonment. On 3D seismic data the morphology of a fluvial distributary channel is often slightly sinuous and can easily be mistaken for part of a meander channel belt.Fluvial distributary channels are usually thinner and shallower compared to their updip fluvial channel belts. Width-thickness ratios for fluvial distributary channel reservoirs are on average 50:1 (range 15:1 to 100:1), while meandering fluvial channel reservoirs have widththickness ratios typically >100:1, and braided river reservoirs show ratios of 500:1 or higher. Examples from the Mahakam Delta are used to illustrate these issues. Implications for exploration and development of deltaic deposits on the North West Shelf of Australia are discussed.
THE NEW ROYAL OIL FIELD: A CASE HISTORY OF THE DISCOVERY AND APPRAISAL OF A SUBTLE, STRATIGRAPHICALLY TRAPPED HYDROCARBON ACCUMULATION IN THE TRIASSIC SHOWGROUNDS SANDSTONE, SURAT BASIN
Authors: Willink R.J. , Harvey R.L.
Published: August 2017

The New Royal Oil Field is located in a structural embayment on the eastern flank of the Kincora High, western Surat Basin, Queensland. Hydrocarbons have accumulated in the Middle Triassic Showgrounds Sandstone, specifically in a thin basal fluvial unit, interpreted as part of an incised valley fill deposit, that displays excellent reservoir properties but is highly localised in its distribution. The Showgrounds Sandstone overlies either granitic basement or a veneer of Permian clastics including coals. Whereas the Showgrounds Sandstone is an established hydrocarbon bearing reservoir in a number of structural settings elsewhere in the basin, trapping in the New Royal field is primarily stratigraphic.Since its discovery in November 1995, various exploration techniques and technologies have been applied, including the acquisition of 3D seismic data, in an attempt to understand the trapping mechanism of this field and predict its lateral extent, albeit with mixed success. Twelve wells have now been drilled in the greater New Royal field area, only four of which were successfully completed as oil producers from the basal Showgrounds Sandstone. Production to date totals 1.1 million barrels of oil and reservoir simulation studies indicate that original-oil-in-place was 4.6 million barrels.This case history serves as a timely reminder that despite all the technology now available to the petroleum geoscientist, serendipity still plays an important role in the discovery and successful appraisal of certain hydrocarbon accumulations in the Surat Basin.
PETROPHYSICAL PROPERTIES DERIVED FROM X-RAY CT IMAGES
Authors: Arns C.H. , Sakellariou A. , Senden T.J. , Sheppard A.P. , Sok R.M. , Pinczewski W.V. , Knackstedt M.A.
Published: August 2017

A micro-CT facility for imaging, visualising and modelling sedimentary rock properties in three dimensions (3D) is described. The facility is capable of acquiring 3D X-ray CT images of full-diameter cores and core plugs at up to 2,0003 voxels with resolutions down to 2μm. This allows the 3D pore-space of a rock to be imaged and, with the aid of SEM, to identify regions of different mineralogy. Computational results are presented which demonstrate that accurate predictions of petrophysical properties can be made directly from the digitised tomographic images. Computations of both formation factor and permeability from micro-tomographic images of Fontainebleau sandstone are shown to be in excellent agreement with experimental measurements over a wide range of porosities. Computed elastic properties for dry and water-saturated conditions are shown to be consistent with the exact Gassmann’s equations and are in excellent agreement with experimental measurements. Experimental measurements of Vp/Vs ratio for cemented sandstone morphologies are very noisy and cannot be used to infer relationships between elastic properties, mineralogy and rock microstructure. Computations on tomographic images show that the Vp/Vs ratio exhibits predictable limiting behavior which holds for any number of solid phases and is insensitive to the manner in which the phases are distributed. This allows the development of more accurate empirical methods for deriving the full velocity-porosity relationship for cemented sands. The results demonstrate the feasibility of combining digitised images with numerical calculations to accurately predict petrophysical properties of individual rock morphologies.
A STATE-OF-THE-ART REVIEW OF FUZZY LOGIC FOR RESERVOIR EVALUATION
Authors: Wong K.W. , Wong P.M. , Gedeon T.D. , Fung C.C.
Published: August 2017

The application of new mathematics using fuzzy logic has been successful in several areas of petroleum engineering. This paper reviews the state-of-the-art of fuzzy logic applied to reservoir evaluation, especially in the area of petrophysical properties prediction and lithofacies prediction from well logs. In this paper, we will also review some fuzzy methods that have been successfully applied to case studies. Besides using fuzzy logic in establishing the model itself, fuzzy logic is also used in some cases as pre-processing or post-processing tools. This paper will act as a guide for petroleum engineers to take advantage of these advanced technologies as well as those undertaking research in this field.
DEALING WITH CLIMATE CHANGE: POSSIBLE PATHWAYS FORWARD
Authors: Fisher B.S. , Jakeman G.N. , Woffenden K.G. , Tulpulé V.A. , Hester S.T.
Published: August 2017

Under the United Nations Framework Convention on Climate Change, the international community has sought to find a policy framework to address the threat of human induced climate change. The most significant action to date has been the adoption of the Kyoto Protocol in December 1997, which could enter into force in 2003. The protocol includes legally binding emission reductions for some countries over the period 2008–12.It has yet not been possible, however, to find an approach that is truly global and that is aligned with the long-term environmental goal of reducing global greenhouse gas emissions to a safe level.A framework for action that addresses these shortcomings is developed in this paper. The underlying tenets are environmental effectiveness, economic efficiency, and equity. The power of technology is drawn into the solution, the importance of an appropriate timeframe for action is acknowledged and involvement by all major emitting countries is facilitated. Importantly, this last point includes participation by developing countries in a way that accommodates their aspirations for economic growth. Together, these elements allow a response that minimises costs and maximises the environmental outcome while at the same time enhancing the growth prospects of developing countries.
ONSHORE OTWAY BASIN CARBON DIOXIDE ACCUMULATIONS: CO2-INDUCED DIAGENESIS IN NATURAL ANALOGUES FOR UNDERGROUND STORAGE OF GREENHOUSE GAS
Authors: Watson N.M. , Zwingmann N. , Lemon N.M. , Tingate P.R.
Published: August 2017

The study of natural carbon dioxide (CO2) accumulations, such as those found in the onshore Otway Basin, is necessary for the validation of underground long-term storage technology as an option for decreasing greenhouse gas emissions.The investigation of natural CO2 occurrences is being investigated as part of the Geological Disposal of Carbon Dioxide (GEODISC) research program. This study identifies the effects of CO2 on reservoir rock’s mineralogy through time as well as its porosity and permeability. The Otway Basin CO2 accumulations display variations in reservoir type, CO2 concentration and time of injection. A range of typical reservoirs types for the CO2 accumulations occurs in the Otway Basin, including feldspathic litharenites, subfeldsarenite and quartz arenite. CO2 concentrations in the Otway Basin vary greatly in the accumulations studied, ranging from 10 mol% within the Port Campbell Field to 99 mol % in the Caroline Field. The source of the CO2 is degassing of the deep-seated magmas of the Newer Volcanics, with CO2 influx occurring between ~2 million to as recently as 5,000 years ago. This study investigated three areas of the Otway Basin;Penola Trough—Ladbroke Grove, Katnook (non-CO2)Port Campbell Embayment—Boggy Creek, Langley, Port Campbell; andGambier Sub-Basin—CarolineDue to their close proximity and similar geological history prior to CO2 influx, the Ladbroke Grove-Katnook gas accumulations are particularly useful for examining differences between a CO2-rich (Ladbroke Grove) and a CO2-absent field (Katnook) and for developing a post- CO2 diagenetic history. Variation in grain size and CO2 concentration affects the degree of reaction of CO2 with the reservoir rock. Petrology and formation water chemistry of these fields indicate that CO2 has modified the rock properties. In all CO2-rich reservoirs examined (>10 mol % CO2), dissolution and alteration of lithic and felsic framework grains has occurred (e.g. albite dissolution). Clays and cements throughout most of the Otway Basin CO2 accumulations are modified to minerals more stable in the changed gas compositions (e.g. chlorite to kaolin). The change in mineralogy after the recent CO2 influx shows that the Pretty Hill Formation with high amounts of reactive minerals and smaller grain size is an effective reservoir unit for mineral storage of CO2. Longterm storage in the Waarre Sandstone quartz-rich reservoirs also displays the effectiveness of CO2 storage in pore space.This study of natural accumulations of CO2 has demonstrated that geological storage of CO2 is a viable option. Understanding of the mineral reactions involved with CO2 in reservoir rock is vital for selection of storage sites and modelling the behaviour of CO2 in the subsurface.
THE FISCAL SETTINGS THAT ARE IMPORTANT TO PETROLEUM EXPLORATION AND DEVELOPMENT IN AUSTRALIA
Authors: Lawry M.J.
Published: August 2017

A fiscal regime must reflect the underlying characteristics of the petroleum industry. Australia’s fiscal settings do not sufficiently reflect the current and future characteristics of the industry, particularly frontier deepwater exploration activity. The fiscal system can encourage greater exploration by providing more immediate access to tax benefits for exploration for all taxpayers, adjustment of the PRRT augmentation rules to better reflect time lags and improving development economics for high risk projects. Competing international regimes exhibit a greater flexibility of fiscal terms required to attract investment. Common petroleum industry arrangements, such as farm-ins should be free from any tax uncertainty. Tax legislation should be amended on a timely basis to correct technical anomalies or uncertainties.
AVOIDING CAPITAL COST BLOWOUTS ON OIL AND GAS PROJECTS
Authors: Hogarth R.A.
Published: August 2017

Modern corporate practices have been slow to come to grips with the risks of large capital expenditure projects, particularly the processes of due diligence on investment submissions and high level monitoring of project implementation.Unlike the mining sector where major project cost blowouts have received intense public scrutiny, collection of data on this issue is difficult in the oil and gas sector and there remains a reluctance of companies to share horror stories. The increasing trend towards company acquisitions rather than exploration, the rates of return on capital investments reported by oil and gas companies and the data available on this issue within the mining industry point towards a potential problem for the oil and gas industry and one that, with appropriate corporate practice could be more readily identified.This paper puts forward the case for more effective corporate practices in relation to large capital projects in optimising return on capital and discusses the role of project owner senior management and the key factors impacting on capital expenditure blowouts.Effective project due diligence, monitoring of project implementation and integration management are put forward as the three key focuses for Boards and management in ensuring that cost blowouts are avoided.
ACCESS TO AUSTRALIAN EXPLORATION AND PRODUCTION DATA: A CRITICAL FACTOR IN ATTRACTING INVESTMENT
Authors: Williamson P.E. , Foster C.B.
Published: August 2017

During the past 10 years, Australia has maintained 65– 85% self-sufficiency in oil and better than 100% sufficiency in gas. This has generated significant societal benefits in terms of employment, balance of payments, and revenue. The decline of the super-giant Gippsland fields, discovery of smaller oil pools on the North West Shelf, and the increasing reliance on condensate to sustain our liquids supply, however, sharpens the focus on Australia’s need to increase exploration and discover more oil. Australia is competing in the global market place for exploration funds, but as it is relatively underexplored there is a need to simulate interest through access to pre-competitive data and information. Public access to exploration and production data is a key plank in Australian promotion of petroleum exploration acreage. Access results from legislation that initially subsidised exploration in return for lodgement and public availability of exploration and production (E&P) data. Today publicly available E&P data ranges from digital seismic tapes, to core and cuttings samples from wells, and access to relational databases, including organic geochemistry, biostratigraphy, and reservoir and shows information. Seismic information is being progressively consolidated to high density media. Under the Commonwealth Government’s Spatial Information and Data Access Policy, announced in 2001, company data are publicly available at the cost of transfer, after a relatively brief confidentiality period. In addition, pre-competitive regional studies relating to petroleum prospectivity, undertaken by Government, and databases and spatial information are free over the Internet, further reducing the cost of exploration. In cooperation with the Australian States and the Northern Territory, we are working towards jointly presenting Australian opportunities through the Geoscience Portal (http:// www.geoscience.gov.au) and a virtual one-stop data repository. The challenge now is to translate data availability to increased exploration uptake, through client information, and through ever-improving on-line access.
CAN SUSTAINABLE DEVELOPMENT THINKING BE APPLIED TO NEW OILFIELDS? A CASE STUDY OF THE EARLY STAGES OF THE ENFIELD AREA DEVELOPMENT IN AN ENVIRONMENTALLY AND SOCIALLY SENSITIVE AREA
Authors: Baronie F.M. , Fenton M. , Harman G. , Jury M.
Published: August 2017

Can development of a finite resource, such as oil, be consistent with sustainable development? Sustainable development involves meeting the needs of current and future generations through simultaneous consideration of environmental, social and economic aspects (referred to as the triple bottom line).Since 1998, Woodside Energy Ltd (Woodside) has discovered three oil fields in the WA-271-P Permit area offshore North West Cape, northern Western Australia. The fields are some 20 km from the boundary of the Ningaloo Marine Park.The first part of this paper presents a case study of the Enfield Area Development. It describes the approach taken to simultaneously manage environmental, social and economic considerations while planning for the development of oil fields in exploration permit WA-271-P.A range of measures have been employed that are considered examples of best practice for the petroleum industry in Australia, including:early commitment to a range of responsible environmental management measures in design; a comprehensive community engagement program, with links to the development and environmental assessment processes; and pioneering environmental research.Novel methods of establishing environmental and social issues as key priorities within the Woodside development team have been successfully implemented.The case study provides by giving an overview of the most significant environmental risks associated with the proposed development, and concludes that the development does not represent a significant risk to the environment.The second part of the paper then addresses the question of whether oilfields can be developed sustainably, looking at current views from the literature, and whether the approach outlined in the case study can be considered sustainable.While the project is still in an early stage of development, it provides a strong indication that oil development can be consistent with current thinking on sustainability, provided that current needs, which include a dependence on fossil fuels, and future needs, such as preservation of the productive and social value of the environmental resource base, are balanced simultaneously. The paper concludes that oil development, even in an environmentally and socially sensitive area, can help facilitate the transition to a more sustainable future.
ASSESSMENT AND APPROVAL OF PETROLEUM ACTIVITIES UNDER THE COMMONWEALTH ENVIRONMENT PROTECTION AND BIODIVERSITY CONSERVATION ACT 1999—LESSONS LEARNED
Authors: Heiden K.
Published: August 2017

This paper provides a brief overview of the Environment Protection and Biodiversity Conservation Act 1999 (the Act) with respect to the upstream petroleum industry and focusses on the aspects of assessments and approvals under the Act.The inception of the Act on 16 July 2000 has created a new environmental assessment and approval regime at the Commonwealth level. No longer are proposals referred for assessment on the basis of government decisions, but on the basis of the potential for a proposal to impact upon a matter of National Environmental Significance (NES). Examining the statistics of referrals made, controlled actions determined and approvals granted, provides a useful guide as to the types of activities that are captured by the Act. This exercise is particularly valuable for the oil and gas sector.With more than 20 of the referrals received from the petroleum sector being determined to be controlled actions (that is, actions that are likely to have a significant impact upon matters of NES), a review of the assessment and approval processes under the Act provides some useful insights into what factors to consider when seeking approval under the Act. In particular, information on the timeframes involved, extent of information required, form and scope of approval conditions and synergies with other approval requirements provide valuable insights to proponents and can assist in planning future activities in a manner that is consistent with both the requirements of the Act and those of the proposed action.This paper identifies key issues and lessons for proponents when seeking approval under the Act and also identifies areas where industry can work closely with the Commonwealth Government in ways to achieve a balance between environmental protection and the continued development of the oil and gas industry.
EXPLORATION REVIEW
Authors: Schwebel D.
Published: August 2017

Both exploration expenditure and drilling were significantly down in 2002 in comparison to 2001. This quiet phase is primarily due to the evaluation of the 2001 drilling and seismic results which should lead, in the long term, to the next cycle of prospect drilling and re-evaluation.The amount of onshore 2D seismic acquisition data gathered was similar to 2001 with most data acquired primarily in the producing basins.Offshore seismic acquisition was down markedly due the completion of a number of major 3D surveys. These data are now in the processing and interpretation phase and when completed will identify the next drilling candidates.The continued success story of the offshore Otway Basin has re-invigorated exploration interest in Australia’s southern margins with exploration continuing to ramp up in the Bight Basin. In the west, the further evaluation of the offshore Perth Basin indicates renewed interest as a result of the Cliff Head discovery.
EVOLUTION OF TIMOR SEA TREATY AND IMPACTS ON CONTRACTORS
Authors: Barrymore S.J.
Published: August 2017

Since the de-annexation of East Timor from Indonesia, the status of the production sharing contracts issued under the Timor Gap Treaty between Australia and Indonesia has been uncertain. The Zone of Co-operation has been administered pursuant to interim arrangements agreed between Australia and UNTAET, the United Nations authority responsible for the administration of East Timor. With the exception of the development activities being carried on in connection with the Bayu-Undan Field, work by the contractors under their PSC’s has basically halted. The contractors have in effect been in a state of force majeure.On 20 May 2002, Australia and East Timor signed a Treaty for the further development of the region, now known as the joint petroleum development Area. A number of significant changes have been made. At the time of preparing this abstract the Treaty has not been ratified and the exact form of the production sharing contracts to be offered to the existing contractors is not known. The arrangements under the Timor Sea Treaty are interim only and can be changed upon permanent delimitation of the seabed boundaries. Australia and East Timor have indicated that they intend to proceed to negotiate those boundaries.This paper will analyse the history of the negotiations and their outcome, the international unitisation agreement, the positions of the existing holders of production sharing contracts and how their rights are to be transitioned through to the new regime. The paper will report on the new issues and risks that arise for contractors who have existing titles and those who are seeking to invest in the JPDA and on any changes to commercial terms.
PERMIAN TO LOWER CRETACEOUS PLATE TECTONICS AND ITS IMPACT ON THE TECTONO-STRATIGRAPHIC DEVELOPMENT OF THE WESTERN AUSTRALIAN MARGIN
Authors: Jablonski D. , Saitta A.J.
Published: August 2017

The post-Lower Permian succession of the Perth Basin and Westralian Superbasin can be directly related to the plate tectonic evolution of the Gondwanan Super-continent. In the Late Permian to Albian the northern edge of Gondwana continued to break into microplates that migrated to the north and were accreted into what is today the southeastern Asia (Burma–China) region. These separation events are recorded as a series of stratigraphically distinct transgressions (corresponding to the initial stretching of the asthenosphere and acceleration of subsidence rates) followed by rapid regressions (when new oceanic crust was emplaced in thinned continental crust causing uplifts of large continental masses). Because the events are synchronous across large regions, and may be identified from specific log and seismic signatures, the intensity of stratigraphically related transgressive/regressive cycles varies, depending on the distance from the break-up centres and these cycles allow the identification of regionally significant megasequences even in undrilled areas. The tectonic evolution and resulting stratigraphy can be described by eight plate tectonic events:Visean (Carboniferous) break-up of the southeastern Asia (Simao, Indochina and South China);Kungurian (uppermost Early Permian) break-up of Qiangtang and Sibumasu;Lowermost Norian uplift due to Bowen Orogeny in eastern Australia;Hettangian break-up of Mangkalihat (northeastern Borneo);Oxfordian break-up of Argo/West Burma, and Sikuleh (Western Sumatra);Kimmeridgian break-up of the West Sulawesi microplate;Tithonian break-up of Paternoster-Meratus (central Borneo); andValanginian break-up of Greater India/India.These events should be identifiable in all Australian Phanerozoic basins and beyond, potentially providing a template for a synchronisation of the Permian to Early Cretaceous stratigraphy.
COMPRESSIONAL GROWTH OF THE MINERVA ANTICLINE, OTWAY BASIN, SOUTHEAST AUSTRALIA—EVIDENCE OF OBLIQUE RIFTING
Authors: Schneider C.L. , Hill K.C. , Hoffman N.
Published: August 2017

Shipwreck Trough, east-central Otway Basin, evolved through Early Cretaceous to Santonian extension, followed by Campanian–Paleocene and Miocene to Recent pulses of compression.Onshore to offshore correlation of seismic sequences combined with 3D seismic mapping reveals that the Minerva anticline is located above an Early Cretaceous, northeast trending, basement-involved, graben. The graben-forming, northeast and north–south trending faults became largely inactive prior to the end of the Early Cretaceous. During the Turonian to Santonian, the northeast trending Point Ronald anticline and newly formed east–west trending normal faults controlled sediment distribution. The structural style changed in the Campanian as the northeast trending Minerva anticline began to form with a coeval, northwest-trending, axial-perpendicular fault array located along the crest of the fold. The location and orientation of this fault set is consistent with a compressional mechanism for fold growth. Similar compressional folding events during the Miocene–Recent modified and tightened the fold. Isopach maps show that during the Campanian to Maastrichtian, sediment thinned onto the nascent Minerva anticline, but accommodation rate outpaced structural growth, preserving a continuous sedimentary sequence.The timing of compressional fold growth is enigmatic. Campanian–Maastrichtian compression at the Minerva anticline was synchronous with over 10 km of extension accommodated by the Tartwaup–Mussel hingeline, 50 km to the south. Although the compression may be far-field effects associated with Tasman Basin sea floor spreading, we speculate that the Minerva anticline grew by transpression within a larger left-lateral transtensional Shipwreck Trough.
FAULT AND TOP SEAL INTEGRITY AT RELAYS AND INTERSECTIONS USING A 3D DISTINCT ELEMENT CODE
Authors: Camac B.A. , Hunt S.P. , Boult P.J.
Published: August 2017

It has long been known that faults and horizon boundaries can greatly affect the magnitude and orientation of the in-situ rock stress state. Significant success has been shown in the geo-engineering disciplines, whereby geomechanical models have been built to model local stress fields generated by rock mass inhomogeneities.In this work 3DEC (3D) the discrete element code has been applied to model stress perturbations around three simple fault configurations, two relay configurations (relay ramp and horst structure) and one fault intersection. The results show rotation in the principal stress orientation and stress magnitudes of the regional stress field about the faults. The degree of rotation of the principal stress direction and the stress magnitude are dependant on the fault friction angle parameter, the angle of maximum principal stress to the fault plane and the ratio of maximum to minimum principal stress. The degree of perturbation is demonstrated graphically in the surrounding rock mass along the fault strike, the perturbation generated by the fault can be up to 1.4 times the magnitude of the maximum principal regional stress and is highly dependent on friction angle.Case studies are presented where this 3D numerical technique has been used to truly integrate risking methods on the fault plane and in the surrounding rock mass. Case study examples are given for the Otway Basin, South Australia and the Bonaparte Basin, Timor Sea, where these predictors can be applied to accurately identify high-risk reservoir seals.
LOGGING WHILE DRILLING IMAGES PROVIDE THE FULL PICTURE
Authors: Wilson M. , Advent F. , Magee T. , Horan S.
Published: August 2017

The range of scenarios and response equation are extremely useful in testing development options that would otherwise not be apparent. The technique rapidly captures the range of likely outcomes and immediately focusses effort onto a flexible approach to the main uncertainties. This saves considerable re-work and development time.
SHARED INFRASTRUCTURE: A COST-EFFECTIVE DEVELOPMENT STRATEGY FOR SMALLER FIELDS OFFSHORE AUSTRALIA?
Authors: Ronalds B.F.
Published: August 2017

B.F. RonaldsFuture oil discoveries offshore Australia are unlikely to be large fields that can support the development of a one-off self-sufficient facility. Fixed platforms are generally only feasible in shallow water when the water depth (in metres) to well count ratio d/w The construction and ongoing re-use of a generic FPSO suited to Australasian field conditions might be of considerable assistance in monetising small oil fields in deeper water. Similarly, aptly located, designed and operated gas hubs could open up large areas for satellite gas development long into the future, aided by new technology to enable ultra-long tiebacks. Both approaches suggest the benefit of overlaying a regional perspective on the oil companies’ field-specific development philosophy.
DEVELOPING COAL SEAM METHANE IN THE SYDNEY BASIN
Authors: Wang I. , Choudhury J. , Barker W. , McNally S.
Published: August 2017

Sydney Gas Ltd (SGL) believes that the growth of the new and exciting coal seam methane (CSM) industry will certainly offer significant economic, social, and environmental benefits to the State of NSW within both the short and the long-term.This paper overviews SGL’s CSM resource development program for the Sydney Basin in general. SGL’s acreage provides an extensive contiguous coverage of the Sydney Basin, and is ideal as it straddles the main gas transmission line from Wollongong to Newcastle.Gas content is one of the most crucial parameters for CSM resource development. This paper also discusses the method adopted by SGL highlighting the pitfalls in the gas content measurements adopted by previous explorers that caused substantial under-estimation of the CSM resource in the Southern Sydney Basin. Gas content determination comprises three components, i.e. lost gas (Q1), desorbed gas (Q2) and residual gas (Q3). Evaluation of earlier data acquired under an ambient temperature rather than reservoir temperature, was the first source of error which resulted in under-estimating gas content calculation. Zero time for desorption measurements was previously set at core retrieval time rather than core cutting time generating an additional error. That is particularly significant in a highly stress-sensitive coal seam such as the Bulli which is the main target for the CSM resource development in the Southern Sydney Basin.This paper has also addressed the commercial case for developing CSM as a new energy source in NSW, for so long dependent upon coal and interstate gas.
GROWTH, PROTECTION AND VALUE REALISATION USING DERIVATIVES
Authors: Heard D.M. , Grenfell S.J.
Published: August 2017

Oil and gas producers are familiar with the use of derivatives to hedge oil price risk.Beyond this, derivatives provide opportunities to enhance more general corporate finance activities.An example is raising finance for acquisitions or developments. When the maximum senior debt has been obtained, the choice between equity funding or other sources (such as subordinated debt) should also consider the up-front cash available from a structured derivative program—this may lower the overall cost of capital for the acquirer, and directly improve equity returns through lower dilution.A notable aspect of oil and gas production businesses is the high degree of embedded optionality. Option pricing methods can be used to value and monetise these real options—creating a new source of finance by transferring part of this embedded optionality to a party which can explicitly value and trade it.Generating value from real options (such as the opportunity to develop a proven, undeveloped reserve) can represent a critical source of finance.The value of such development assets is not fully recognised by traditional lending banks when the final investment decision remains some way off.By contrast, monetising real option value can provide funds at a point where they can be applied to appraisal drilling, thus funding the development of the project to a point where conventional debt or project-secured debt becomes feasible.Companies with both existing unhedged future production and a portfolio of PUD real options are best-placed to benefit from this source of finance.
ALTERNATIVE RESERVE REPORTING AND EXPLORATION ACCOUNTING METHODS—THE NEED FOR INTERNATIONAL ACCOUNTING STANDARDS
Authors: Steedman B.P.
Published: August 2017

The objective of this paper is to analyse the different reserve reporting and exploration accounting methods used globally and highlight the key reporting implications for companies that are domiciled in Australia. This has become a critical issue in the oil and gas sector with the impending implementation of International Accounting Standards (IAS), as these standards as they now stand, do not specifically address the oil and gas industry. As a result companies may have the option or may be required to make significant changes to existing accounting and reporting practices.The paper will analyse the issues, potential implications, and opportunities within the following areas:A brief summary of the history of oil and gas accounting standards and the status of existing IAS.The different reserve reporting practices for exploration accounting and reserve reporting practices between the United States (US), United Kingdom (UK), and Australia, including the different interpretations of reserves within the countries.The alternative accounting outcomes for exploration expenditure depending upon whether successful efforts are applied, area of interest, or full cost accounting.The relationship between reserve reporting and exploration accounting, with examples of how multiple accounting outcomes may result from the same exploration program.Discuss the actions required by oil and gas executives to best manage the issues.The paper will be written and presented in a style such that non-accountants or reserve experts will be able to understand the issues. Detailed analysis of technical issues and industry specific references will be avoided e.g. accounting jargon.The paper will be of most value to representatives of Australian independent oil and gas companies, but would also be of interest to international companies.
A CAREER DEVELOPMENT STRATEGY FOR ASUSTAINABLE, SAFE AND COMPETITIVEAUSTRALIAN ENERGY INDUSTRY
Authors: Starling S. , Robertson J.
Published: August 2017

The Australian upstream oil and gas industry faces many staffing challenges, including:shortages of skilled personnel to staff new developments and expansion projects;retirement of an aging workforce with consequent loss of experience; andlow enrolments in university courses predicting a diminished pool of geologists, engineers and technical staff.APPEA’s Workplace Competency Initiative has been addressing these challenges by devising and promoting a career development strategy to encourage the recruitment and retention of staff. This career development strategy also addresses the competent workforce provisions and duty of care requirements of APPEA’s safety case guidelines. The principle components of the career development strategies are;competency standards—the development of competency standards for production operators and drilling crews;career guide—a promotional publication to attract new recruits, retain current staff, and to promote life-long learning;coach’s handbook—a manual for team leaders, supervisors and managers to encourage staff coaching, competency-based training and career development;coach the coach courses—practical one day sessions to promote staff coaching, competency formation and career development;group training scheme—an industry sponsored scheme to recruit, place and train production operators; anda competency register—development of a competency register to encourage and record workforce safety certificates, workplace inductions and vocational qualifications.Ultimately this career development strategy will create a sustainable pool of skilled workers, contribute to safer workplaces, and improve the competitiveness of the Australian petroleum industry.
APPLYING WHAT WE KNOW ABOUT HUMAN ERROR: FROM THEORY INTO PRACTICE
Authors: Grey E. , Wilkinson P.
Published: August 2017

Human error is often said to be at the heart of the majority of incidents and the developing discipline of human factors a way of understanding how these errors occur. There is little debate about this. But do we practise what we preach and are we reaping the benefits of applying the insights? Anecdotal evidence suggests not. Human error is too often interpreted as people being reckless, careless or just ignorant in discharging their duties. This so-called careless worker approach was the unstated assumption behind early moves to improve health and safety. It could be argued in the petroleum industry that we have adopted a more sophisticated approach, emphasising the importance of the engineering integrity of process systems and the role of formal management systems. However, there remains a need to better integrate what we know about human and organisational error. Reason’s (1997) organisational accident model has had a profound effect on how accidents are viewed and how we can learn from them. The clarity with which the model is presented does not, however, necessarily translate directly into ease of application. The model is a description of accident causation, but does not provide a method for making assessments about organisational resilience in its own right. As such, individuals wanting to use the model need to be well trained if benefits are to be realised. This paper describes a practical and applied approach to human error training based on principles of adult learning that is designed to tap into trainees’ existing knowledge and experiences.
GEOSTEERING OF TWO HORIZONTAL WELLS IN SOUTH UMM GUDAIR FIELD: A SUCCESSFUL CASE HISTORY
Authors: Jha M. , Tran T. , Hawkins D.
Published: August 2017

The South Umm Gudair (SUG) oil field located in the Neutral zone between Kuwait and Saudi Arabia has produced since 1968 from an active water drive carbonate reservoir of Lower Cretaceous age. The lower zones are homogenous intervals of higher permeability which appear to be sufficiently swept by natural water drive over a period of time. The upper zones of the reservoir have lower permeability, are relatively thin and are bound by tighter intervals that act as possible barriers to the natural water drive system.Geosteering techniques are now extensively used in oil and gas industry for horizontal wells to produce hydrocarbons from thin reservoirs to maximise recovery, and restricting water-coning problems. Recent advancements in well placement using Geosteering allow successful targetting of low permeability reservoir with great precision which results in exposing more drainage area in the target pay.The geosteering technique was considered for the first time in joint operation’s SUG field targetting two horizontal wells. Improved well productivity is achieved through optimised well placement. This success has led to a development plan and strategy of additional horizontal drilling locations to maximise recovery of un-swept oil from the low permeability reservoirs. This paper reviews the success of Geosteering in SUG’s two horizontal wells, completed in July 2004.
A MULTI-DISCIPLINARY APPROACH DELIVERS QUALITY RESULTS TO A COMPLEX FORMATION EVALUATION PROBLEM
Authors: Magee T.J. , Gray T.A. , Kelly J.C. , White L.B.
Published: August 2017

This paper illustrates the benefits of a multi-disciplinary approach to formation evaluation in an interbedded sand/ shale reservoir sequence. The Egret–3 appraisal well was drilled to obtain information to evaluate the commercial viability of the Egret oil field. A key objective of the well was to test for the presence of a gas cap and, if present, to confirm the gas-oil contact (GOC).A number of analytical techniques were employed to distinguish between oil and gas in the reservoir; these included analysis of mudlog gas ratios, evaluation of separation between the density and neutron logs, pressure gradient analysis, formation fluid sampling and PVT and geochemical analyses. Each method confirmed the presence of a gas cap, but indicated a different GOC. It was only by combining the full suite of tools that the uncertainty associated with the GOC could be accurately defined.Key elements contributing to the success of the program included: clear recognition of the significance of gas cap to commercial viability of the Egret oil development; design and planning of an appropriate formation evaluation program; flexibility in implementation of the program and determination and alignment amongst all disciplines to overcome operational difficulties.