bluuebunny/crossref_metadata_2025 huggingface dataset:
ACQUISITION TECHNOLOGY OPENS UP DIFFICULT DATA AREAS FOR 3D EXPLORATION
Authors: Ramsden C.R.T , Long A.S
Published: August 2017

3D seismic technologies have advanced rapidly during the 1990s. The new generation of seismic vessels such as the Ramform design with their massive towing capacities has changed the way in which modern seismic data is acquired. This has resulted in a large increase worldwide in the use of 3D seismic data during the exploration phase because of the reduction in the cost of 3D data. A statistical database has emerged showing that drilling on 3D data will double the commercial success rate compared to drilling on 2D data.Historically, dual-source acquisition has dominated exploration (by comparison to single-source acquisition) due to cost savings associated with the fact that singlesource acquisition implies a geophysical requirement to tow the streamers at half the separation of dual-source acquisition. Data quality associated with single-source acquisition, however, is typically much superior to dualsource data. The ability now to tow 12–16 streamers has reduced costs so that single-source acquisition is now cost effective. The surveys using single-source acquisition allow 3D data to be acquired with significantly higher trace densities and crew efficiencies than industry standard, and are called High Density 3D or HD3D. These surveys have benefits of increased fold, improved spatial resolution and improved imaging quality, and can now be routinely conducted, especially in difficult data areas.The North West Shelf of Australia is a difficult data area because of the presence of strong multiple noise trains that often mask or interfere with the primary reflections (Ramdsen et al, 1988). Standard multiple attenuation techniques have had only limited success. HD3D with its higher trace density and 40% improvement in signal-to-noise ratio has resulted in improved data quality in difficult data areas, and should result in data improvements on the North West Shelf as well.Furthermore, the Continuous Long Offset (CLO) recording technique using Ramform technology is a dualvessel operation that has demonstrated significant operational efficiency improvements in long offset (typically deep water/targets) 3D seismic acquisition. Survey turnaround times can be reduced by as much as half of those using conventional techniques. The CLO technique is particularly well suited for deepwater recording.
TAX REFORM IN THE OIL INDUSTRY
Authors: Williamson M.
Published: August 2017

Following the return of the Liberal National Country Party for its second term of office under the Prime Minister, Mr John Howard, the Federal Government established a committee headed by a business executive Mr John Ralph. This Committee produced an extensive report recommending substantial changes to the Australian tax legislation. Following consideration of the report by the Federal Government, substantial amendments were proposed in September and November 1999. Many of these proposals have now been legislated and several remain in the pipeline awaiting Parliament scrutiny.This paper covers the practical aspects of the changes to the tax legislation, along with examination of particular issues associated with new developments in matters such as gas banking. Particular focus has been made on the new Uniform Capital Allowances Provisions and the deductions which will be available to the industry against upstream project development expenditures.
OVERVIEW AND REVIEW OF THE COMMONWEALTH ENVIRONMENT PROTECTION AND BIODIVERSITY CONSERVATION ACT 1999
Authors: Heiden K.
Published: August 2017

This paper provides a brief overview of the Environment Protection and Biodiversity Conservation Act 1999 (the Act) and discusses the operational performance of the Act in the first 18 months.The introduction of the Act on 16 July 2000 has created a new environmental assessment and approval regime at the Commonwealth level. Proposals are no longer 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). An analysis of projects that have been referred, assessed and approved provides a useful guide to the types of activities, and the circumstances under which proposals are captured by the Act. This exercise is particularly valuable for the oil and gas sector.With a significant proportion of referrals received being generated by the petroleum industry, many issues with the administration of the Act have been identified. Environment Australia has undertaken a number of initiatives to address these concerns. Examples include involvement in the Strategic Assessment being conducted by the Department of Industry Tourism and Resources (DITR), a review of the Referral form and an undertaking to provide a more industry-specific form, and regular, high level meetings between Environment Australia, the DITR and APPEA to facilitate and streamline the working arrangements between parties.The paper also identifies areas where industry can work closely with the Commonwealth Government in new ways to achieve a balance between environmental protection and the continued development of the oil and gas industry.
CHANGES TO THE ENVIRONMENTAL MANAGEMENT OF PRODUCED FORMATION WATER, OFFSHORE AUSTRA
Authors: Cobby G.L.
Published: August 2017

Under Australian offshore petroleum legislation, produced formation water (PFW) shall not be discharged into the sea unless there is an approved method. Where approval is granted, the concentration of petroleum in any PFW discharged to the sea shall not be greater than 50 mg/l at any one time and the average content over each 24 hour period shall be less than 30 mg/l unless otherwise approved.The introduction of the Commonwealth Petroleum (Submerged Lands) (Management of Environment) Regulations 1999 has changed the way PFW is regulated. The operation of a facility is defined under regulation 4 as a petroleum activity. Regulation 13(3) requires operators to assess the environmental effects and risks of a petroleum activity. The assessment of a facility operation should include the effects and risks associated with PFW discharge.This paper considers how these new requirements affect petroleum operators and what this means for existing and future production facility PFW management. Information is provided regarding assessment tools that are available to measure environmental effect and risk and attempts to describe their ecological relevance and role in decision-making.
CHALLENGES OF THE WORKFORCE AND TRAINING
Authors: Jones Barry
Published: August 2017

The future of the petroleum production and exploration industries must be examined in at least nine contexts: population, social, political, economic, environmental quality, employment and skills, physical flows, resource use and trade. Education and innovation ought to have a major impact on your industries, but universities are facing serious limitations, with a serious decline in students undertaking the enabling sciences (including geosciences), and where an increasing emphasis on the corporatisation of learning /research puts excessive emphasis on the short term.The current political climate discourages serious consideration of complex, long-term factors. Issues such as energy efficiency deserve comprehensive discussion as Australia faces the dilemma of whether to follow the United States pattern of resource use or the European. Australia’s extraordinary tradition of urban development suggests that we will be increasingly heavy users of imported fuel.
2001 EXPLORATION REVIEW
Authors: Mackie S.I.
Published: August 2017

Exploration expenditure in 2001 was the highest ever and successful wildcats were drilled in all major petroleum basins. Much of the success can be attributed to the increasing use of 3D seismic data prior to drilling. Although 2001 saw the first onshore exploration permits awarded since the mid-90s the resolution of Native Title still remains the highest concern for onshore exploration. Decreasing 2D acquisition may indicate failure to be exploring in frontier areas. The discovery of the Thylacine and Geographe fields in the offshore Otway recharged exploration on Australia’s southern margins. The success of Cliff Head–1 in the offshore Perth Basin demonstrates that small independents can still play a major role in Australian exploration.
BASS STRAIT OFFSHORE FACILITY SAFETY CASES: A CASE STUDY ON EFFECTIVE WORKFORCE INVOLVEMENT IN THE MODERN SAFETY CASE REGIME
Authors: Greenwood M.C. , Tyler D.C. , Newton M.A. , Clarke N.V. , Hayes J.J. , Turner C.L.
Published: August 2017

In 2001, Esso submitted 18 different Bass Strait Facility Safety Cases as part of their five year revision cycle, and obtained regulatory acceptance for each of them. These revised safety cases incorporated the accumulated learning from our many previous offshore safety case submissions, the 1998 Longford accident and our work with the WorkSafe Victoria Major Hazards Division. A number of significant challenges were met and overcome. This paper discusses our experiences and describes the processes we used to successfully develop useful, easy to use living safety cases for our offshore workforce.Although our priority was to demonstrate that we knew our facilities, had identified hazards, assessed the risks associated with those hazards and had control measures in place to reduce those risks to as low as reasonably practicable, we also wanted to bring about behavioural change. This paper will explain how our safety case revision processes were used to successfully change workforce behaviours with consequent changes to collective attitudes and values across the organisation.Extensive and highly effective employee involvement was integral to all stages of the safety case planning and development process. The paper examines how a skilled team comprising a workforce-elected Health and Safety Representative, an Offshore Installation Manager and specialist safety professionals collaborated to deliver a true program of workforce involvement and buy-in that in turn delivered the behavioural changes necessary for a true safety case culture to flourish.Esso’s approach of developing a safety case as a shopfloor friendly tool highlighting the linkages between routinely used safety management system controls and the major accident event risks present at the workplace has delivered significant benefit in developing a risk averse health and safety culture. A comprehensive ongoing learning program designed to give the workforce the knowledge, skills and confidence needed to use the safety case to maximum advantage, has been developed as a key component of our safety case program. This paper explores the successful planning, development and implementation of this innovative learning program that has been widely recognised by regulators and industry.
STRUCTURAL FRAMEWORK AND BASIN EVOLUTION OF AUSTRALIA’S SOUTHERN MARGIN
Authors: Teasdale J.P. , Pryer L.L. , Stuart-Smith P.G. , Romine K.K. , Etheridge M.A. , Loutit T.S. , Kyan D.M.
Published: August 2017

The structural evolution of all of the Southern Margin Basins can be explained by episodic reactivation of basement structures in respect to a specific sequence of tectonic events. Three geological provinces dominate the basement geology of the Southern Margin basins. The Eyre, Ceduna, Duntroon and Polda Basins overlie basement of the Archean to Proterozoic Gawler-Antarctic Craton. The Otway and Sorell Basins overlie basement of the Neoproterozoic-early Palaeozoic Adelaide- Kanmantoo Fold Belt. The Bass and Gippsland Basins overlie basement of the Palaeozoic Lachlan Fold Belt. The contrasting basement terranes within the three basement provinces and the structures within and between them significantly influenced the evolution and architecture of the Southern Margin basins.The present-day geometry was established during three Mesozoic extensional basin phases:Late Jurassic–Early Cretaceous NW–SE transtension forming deep rift basins to the west and linked pullapart basins and oblique graben east of the Southwest Ceduna Accommodation Zone; Early–Mid Cretaceous NE–SW extension; and Late Cretaceous NNE–SSW extension leading to continental breakup. At least three, potentially trap forming, inversion events have variably influenced the Southern Margin basins; Mid Cretaceous, Eocene, and Miocene-Recent. Volcanism occurred along the margin during the Late Cretaceous and sporadically through the Tertiary.First-order structural control on Mesozoic rifting and breakup were east–west trending basement structures of the southern Australian fracture zone. Second-order controls include:Proterozoic basement shear zones and/or terrane boundaries in the western Gawler Craton, which controlled basin evolution in the Eyre and Ceduna Subbasins; Neoproterozoic structures, which significantly influenced basin evolution in the Ceduna sub-basin; Cambro-Ordovician basement shear zones and/or terrane boundaries, which were a primary control on basin evolution in the Otway and Sorell Basins; and Palaeozoic structures in the Lachlan Fold Belt, which controlled basin evolution in the Bass and Gippsland Basins.A SEEBASE™ (Structurally Enhanced view of Economic Basement) model for the Southern Margin basins has been constructed to show basement topography. When used in combination with a rigorous interpretation of the structural evolution of the margin, it provides a foundation for basin phase and source rock distribution, hydrocarbon fluid focal points and trap type/distribution.
BEATING THE ODDS AT CASINO!—A SMALL AUSTRALIAN’S EXAMPLE OF RISK MANAGEMENT
Authors: Poynton D.J.
Published: August 2017

Strike Oil was a very small unlisted Australian company with a capitalisation of less than A$10 million when it decided to bid for block V98-4 (now VIC/P44) in the offshore Otway Basin in early 1999.Block V98-4 met Strike Oil’s gas strategy of pursuing opportunities in basins close to infrastructure and markets in the eastern states of Australia.Prior to making the bid Strike Oil identified the geological, financial and operational risks associated with exploring the permit, especially with regard to conducting a 3D seismic survey in the environmentally sensitive and sometimes hostile Bass Strait. This led to the implementation of, and adherence to, a comprehensive risk management plan.The geological risks were addressed by acquiring 3D seismic and conducting an analysis of the amplitudes and AVO responses associated with nearby gas discoveries and dry holes.Management of the financial risk centred firstly around not overbidding and secondly finding a farmee who could add value to the permit during both the exploration and exploitation phases.The operational risks were all associated with conducting the Casino 3D seismic survey. Local environmental considerations, particularly in relation to migratory whale species and the seasonal activities of local fishermen, meant there was only a six weeks’ time window available for unhindered operations. This window also coincided with the spring gale season, when weather conditions can stop marine operations.The use of experienced personnel, early stakeholder consultation, and the use of contingency plans, enabled Strike Oil to achieve its objectives under adverse conditions. The Casino 3D seismic survey, despite the odds, was completed on time, under budget, and with less than 7% infill, while still delivering high quality data.The farmout, the acquisition and processing of the 3D seismic data, and the discovery and appraisal of the Casino gas field were all achieved within 14 months.
COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA
Authors: Boreham C.J. , Blevin J.E. , Radlinski A.P. , Trigg K.R.
Published: August 2017

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.
THE MUTINEER COMPLEX AND EXETER OIL DISCOVERIES: MUTINY IN THE DAMPIER
Authors: Auld K.A. , Redfearn J.E.P.
Published: August 2017

The oil discoveries at Norfolk–1 and Exeter–1 in the Northern Dampier Sub-basin (permit WA-191-P) have realised major commercial potential in an area with a prolonged exploration history. This paper presents the results of the drilling campaign which was undertaken in 2002 comprising two successful exploration discovery and five appraisal wells. The Norfolk–1 (28 m gross oil column), Norfolk–2 (9 m oil column), Exeter–1 (23 m oil column), Mutineer–3 (8 m oil column) and finally Exeter–2 (12 m oil column) confirmed a significant commercial oil volume within the Jurassic Angel Sandstones.The recent exploration of this area has improved understanding of the geology through the integration of technology with geoscientific understanding. Highs have been revealed from seismic time data using advanced 3D seismic techniques and sophisticated depth conversion processes.The time structural high of the Mutineer area was first tested by Bounty–1 in 1983 which is now mapped outside the southern limit of closure. Pitcairn–1 was drilled in 1997 discovering three thin oil columns and was followed by a near crestal well at Mutineer–1B drilled 2.6 km northwest of Pitcairn–1 in 1998, discovering an 8m column. The key issue was the understanding of the velocity gradient and depth conversion over the Mutineer Complex which revealed the true structural picture.This paper summarises results of the exploration and appraisal wells drilled and describes the evolution of the structural/stratigraphic understanding of the area, covering critical components hindering the oil field’s early detection. The first component is a significant seismic velocity gradient which causes true structural closure to be significantly offset from the time closure. The second component is the reservoir pressures within the oil reservoir and older sandstone intervals within the Angel and Legendre Sandstones show differences due to hydrodynamic cells and/or depletion resulting from production from the adjacent NWS Venture oil fields. The final component is the oil is primarily reservoired in the top Angel Sandstone, belonging to the J40 sequence and is sealed by a thin shale from the underlying mainly water bearing sandstones (J35/J30 and Legendre Sandstones).The combined reserves for the Mutineer Complex and Exeter Oil Fields reservoired in these laterally continuous turbidites are estimated to be 70–160 MMBBL recoverable.
THE GERYON, ORTHRUS, MAENAD AND URANIA GAS FIELDS, CARNARVON BASIN, WESTERN AUSTRALIA
Authors: Korn B.E. , Teakle R.P. , Maughan D.M. , Siffleet P.B.
Published: August 2017

The Geryon, Orthrus, Maenad and Urania Gas Fields are located in permit WA-267-P in approximately 1,200 m of water, and between 35 km northwest and 70 km north of the Gorgon Gas Field in the offshore Carnarvon Basin of Western Australia. Five wells were drilled in these fields between August 1999 and February 2001 as part of a six-well, three-year obligatory drilling program. The primary objectives were late Triassic sandstones of the upper Mungaroo Formation. The Geryon and Urania Fields are three-way footwall structures, while the Orthrus and Maenad Fields comprise four-way horst structures where progressively older units subcrop against the Callovian Unconformity. All objective reservoirs were amplitude associated and had strong AVO signatures, which was instrumental in the high exploration success rate and excellent exploration prediction of OGIP from seismic data.This paper will briefly discuss the description of late Triassic and early Jurassic reservoirs and the transition of the AA sand of the Mungaroo Formation from fluvial to marginal marine facies in the Greater Gorgon Area, the recent drilling results of the Triassic Prospects in WA-267-P, and the geophysical attributes of the AA sand Mungaroo Formation reservoirs.The WA-267-P Triassic Gas Fields are estimated to contain approximately 210 billion m3 (7.4 TCF) recoverable sales gas. The close proximity of these Triassic gas fields to each other, the clean gas composition and size of resource base suggests these fields are excellent candidates for a future gas development in Western Australia.
THE JANSZ GAS FIELD, CARNARVON BASIN, AUSTRALIA
Authors: Jenkins C.C. , Maughan D.M. , Acton J.H. , Duckett A. , Korn B.E. , Teakle R.P.
Published: August 2017

The Jansz gas field is located in permit WA-268-P, 70 km northwest of the Gorgon gas field in the Carnarvon Basin. The Jansz–1 discovery well was drilled in April 2000 and intersected 29 m of net gas pay in an Oxfordian age shallow marine sandstone reservoir. The well drilled a stratigraphic trap on the western limb of the Kangaroo Syncline.The Io–1 well was drilled in January 2001 in the adjacent permit WA-267-P (18 km from Jansz–1) and intersected the same Oxfordian sandstone reservoir penetrated by Jansz–1, with a total of 44 m of net gas pay. The Tithonian and the Upper Triassic Brigadier Sandstone gas reservoirs at Geryon–1 (1999) and Callirhoe–1 (2001) in WA-267-P are in pressure communication with the Oxfordian gas reservoir at Jansz–1 and Io–1. Consequently, the three different age reservoirs comprise a single gas pool, with a common gas/water contact.The Jansz gas field has been delineated by four wells and 2D seismic. The gas sandstones have a prominent amplitude versus offset response, which defines the field limits. The Jansz gas field is confirmed by drilling to be an areally extensive (2,000 km2) gas accumulation with a gross column height of 400 m and an estimated 20 TCF (566 G.m3) recoverable sales gas, which represents 40% of the discovered gas resources in the deepwater Carnarvon Basin. The size of the Jansz gas field and its remoteness from existing pipeline gas markets suggests that an export LNG project will be the basis for its development.
OVERCOMING HISTORICAL BIAS: AN INTEGRATED GEOLOGICAL AND ENGINEERING ASSESSMENT OF THE CONISTON PROSPECT, EXMOUTH SUB-BASIN
Authors: Smith N. , Dempsey C. , Jackson M. , Preston J.
Published: August 2017

The discovery of heavily biodegraded oil in Novara–1 in 1982 by Esso/BHP branded the Exmouth Sub-basin as a difficult exploration province for almost two decades. A total of 24 barrels of biodegraded, 16.7o API oil was recovered from a drill-stem test conducted over a 2 m interval, indicating an uneconomic flow rate of 33 BOPD. The perception that any future oil discoveries would be similarly biodegraded and therefore highly problematic, if not impossible, to produce economically, condemned the Exmouth Sub-basin in favour of its eastern cousins— the Barrow and Dampier sub-basins.Despite an encouraging 550 BOPD flow of biodegraded oil from a poor quality reservoir in West Muiron–5 in 1993, it was not until late 1998/9 that flows of 4,300 and 4,800 BOPD from the nearby Woodside wells Vincent–1 and Enfield–1, respectively, demonstrated that biodegraded Exmouth oils could be produced at potentially commercial rates. Concurrent reinterpretation of the Novara–1/ST results, in an integrated geological and engineering assessment, promoted the Coniston prospect adjacent to the Novara fault block.The Novara–1/ST test was demonstrated to have failed largely due to the test parameters, rather than the nature of the oil. Geochemically, the Novara oil is similar to West Muiron–5, so any oil discovered at Coniston had the potential to flow as well as Vincent–1 if a sufficiently thick oil column was encountered in the expected similarly high quality reservoir. Coniston–1 was drilled by BHP/ Mobil in January/February 2000, and flowed biodegraded 15.6° API oil on DST at a rate of 2119 BOPD, restricted by rig and environmental constraints.Historical bias has held back exploration of the Exmouth Sub-basin, leaving this one of the least explored of the Jurassic depocentres within the Carnarvon Basin. The Novara experience encourages explorers to challenge preconceptions and to ensure that the correct mix of technical skills is brought to bear in resolving prospectivity issues. Companies that maintain an active exploration position that allows them to respond rapidly to new concepts stand to gain most when historical biases are overturned.
GEOLOGICAL CONTROLS ON SONIC VELOCITY IN THE CENOZOIC CARBONATES OF THE NORTHERN CARNARVON BASIN, NORTH WEST SHELF, WESTERN AUSTRALIA
Authors: Wallace M.W. , Condilis E. , Powell A. , Redfearn J. , Auld K. , Wiltshire M. , Holdgate G. , Gallagher S.
Published: August 2017

The Cenozoic carbonates of the Bounty-Talisman region can be divided into five major facies. From oldest to youngest, these are: Paleocene to Eocene basinal facies, Oligocene to Miocene slope-canyon facies, Oligocene to Miocene shelf facies, Oligocene to Miocene near-shore facies, and Pliocene-Quaternary shelf facies. This represents a shallowing-upwards cycle up to the late Miocene, followed by a significant transgression and a return to more open marine conditions in the Pliocene- Quaternary. The dominant geological processes controlling sonic velocity in the Cenozoic carbonates are physical compaction, burial calcite cementation, dolomitisation, and anhydrite/gypsum cementation. In the more open marine facies of the Cenozoic carbonates, compaction and burial calcite cementation have been the dominant geological processes that have controlled sonic velocity. Large-scale carbonate content variations associated with submarine canyon-fill sediments have also produced lateral sonic velocity variations. Dolomitisation and anhydrite cementation have produced localised high velocity zones within the near-shore facies of the carbonates.
VISUALISATION OF A FLUVIAL CHANNEL RESERVOIR ANALOGUE FROM THE BIRKHEAD FORMATION, MERRIMELIA, MERANJI AND PELICAN FIELDS, EROMANGA BASIN
Authors: Nakanishi T. , Lang S.C. , Mitchell A.B.
Published: August 2017

The effective production of hydrocarbons from the Birkhead Formation, Eromanga Basin, relies heavily on understanding the complex distribution of reservoir and seal rocks deposited in a fluvial environment. To visualise this complexity, sequence stratigraphic concepts applied to non-marine basins were combined with 3D seismic data visualisation in a study of the Birkhead interval over the Merrimelia, Meranji and Pelican fields.Fluvial channel, crevasse splay channel, floodplaincrevasse splay complex and floodplain facies were recognised from the well log motifs in the Birkhead Formation. The interval is interpreted as an alluvial transgressive systems tract bounded by flooding surfaces consisting of shaly or coaly intervals. Lateral discontinuity of the fluvial system can be demonstrated between these surfaces. Seismic amplitude distributions in the 3D seismic data in the upper part of this transgressive systems tract illustrate well developed meandering fluvial channels. Combining the spatial distributions of sedimentary facies from the well logs and the seismic amplitudes results in the interpretation of a fluvial meandering channel belt that includes point bars and abandoned channels.The point bar sandstones in the channel belt should make good reservoirs and the juxtaposition of the point bar and abandoned channel facies can result in a stratigraphic trap component to the reservoir rocks within the channel belt. Although the point bars are known to be wet in the study area, it is still useful to consider their capacity as oil reservoirs, since they may serve as analogues for similar untested point bars elsewhere. Multiple realisations of the distribution of sandstone thickness of the point bars were generated by conditional simulation, using seismic amplitudes to control extrapolation of the well data. This gave a potential reserves distribution with a mean value of 18.8 million bbl in place. The complexity of the fluvial channel systems in the Birkhead Formation described in this paper should aid understanding of the reservoir and seal distribution and help optimise production from this interval in other fields.
ROCK PHYSICS—APPLICATION TO GEOLOGICAL STORAGE OF CO2
Authors: McKenna J.J. , Gurevich B. , Urosevic M. , Evans B.J.
Published: August 2017

Sequestration of anthropogenic CO2 into underground brine-saturated reservoirs is an immediate option for Australia to reduce CO2 emissions into the atmosphere. Many sites for CO2 storage have been defined within many Australian sedimentary basins. It is anticipated that seismic technology will form the foundation for monitoring CO2 storage within the subsurface, although it is recognised that several other technologies will also be used in support of seismic or in situations where seismic recording is not suitable. The success of seismic monitoring will be determined by the magnitude of the change in the elastic properties of the reservoir during the lifecycle of CO2 storage. In the short-term, there will be a strong contrast in density and compressibility between free CO2 and brine. The contrast between these fluids is greater at shallower depth and higher temperature where CO2 resembles a vapour. The significant change in the elastic moduli of the reservoir will enable time-lapse seismic methods to readily monitor structural or hydrodynamic trapping of CO2 below an impermeable seal. Because the acoustic contrast between brine saturated with CO2 and brine containing no dissolved CO2 is very slight, however, dissolved CO2 is unlikely to be detected by any seismic technology, including high-resolution borehole seismic. The detection of increases in porosity, associated with dissolution of susceptible minerals within the reservoir may provide a means for qualitative monitoring of CO2 dissolution. Conversion of aqueous CO2 into carbonate minerals should cause a detectable rise in the elastic moduli of the rock frame, especially the shear moduli. The magnitude of this rise increases with depth and demonstrates the potential contribution that can be made from repeated shear-wave and multi-component seismic measurements. Forward modelling suggests that the optimal reservoir depth for seismic monitoring of CO2 storage within an unconsolidated reservoir is between 1,000 and 2,500 m. Higher reservoir temperature is also preferred so that free CO2 will resemble a vapour.
BIO-ENHANCEMENT OF COAL BED METHANE RESOURCES IN THE SOUTHERN SYDNEY BASIN
Authors: Faiz M. , Stalker L. , Sherwood N. , Saghafi A. , Wold M. , Barclay S. , Choudhury J. , Barker W. , Wang I.
Published: August 2017

Coals in the Sydney Basin contain large amounts of gas ranging in composition from pure methane (CH4) to pure carbon dioxide (CO2). These gases are derived from thermogenic, magmatic and biogenic sources and their present-day distribution is mainly related to geological structure, depth and proximity to igneous intrusions.A coal bed methane (CBM) study of the Camden area of the Sydney Basin has been jointly conducted by Sydney Gas Company NL (SGC) and the Commonwealth Scientific and Industrial Research Organisation (CSIRO). The delineation of high production fairways is vital for any CBM project development to be commercially successful. An integrated research project employing various methods of reservoir characterisation, including geological, geochemical, geomechanical and gas storage analyses contribute to this delineation for the Camden area, where SGC is currently developing the 300-well Camden Gas Project.In particular, accurate determinations of gas content, saturation levels, composition and origin, as well as interpretations about distribution, are essential for identifying sweet spots for CBM production optimisation. The extent of gas saturation is a function of numerous factors, including amounts of gas generated between the Permian and Late Cretaceous, amounts expelled from the system during Late Cretaceous-Tertiary uplift and amounts of subsequent secondary biogenic methane generated and absorbed in the coals. The extent of this secondary biogenic gas generation appears to be greatest in coals proximal to the basin margins, where meteoric waters carrying bacteria and nutrients had ready access. Significant enhancement of methane content also occurs, however, in deeper parts of the basin where permeable structures exist.The integrated study shows that high production CBM wells drilled to date by SGC are located in zones of enhanced permeability. In these locations original thermogenic wet gases have been removed and additional secondary biogenic methane has been generated due to microbial alteration of coal, hydrocarbons and carbon dioxide. This process has replenished the coals by enhancing the methane contents of the respective seams and this phenomenon can be termed ‘bio-enhancement’ in the context of CBM production.
THE ECONOMICS OF GEOLOGICAL STORAGE OF CO2 IN AUSTRALIA
Authors: Allinson W.G. , Nguyen D.N. , Bradshaw J.
Published: August 2017

The economics of the storage of CO2 in underground reservoirs in Australia have been analysed as part of the Australian Petroleum Cooperative Research Centre’s GEODISC program. The economic analyses in the paper are based on cost estimates generated by a CO2 storage technical/economic model developed at the beginning of the GEODISC project. The estimates rely on data concerning the characteristics of geological reservoirs in Australia. The uncertainties involved in estimating the costs of such projects are discussed and the economics of storing CO2 for a range of CO2 sources and potential storage sites across Australia are presented.The key elements of the CO2 storage process and the methods involved in estimating the costs of CO2 storage are described and the CO2 storage costs for a hypothetical, but representative storage project in Australia are derived. The effects of uncertainties inherent in estimating the costs of storing CO2 are shown.The analyses show that the costs are particularly sensitive to parameters such as the CO2 flow rate, the distance between the source and the storage site, the physical properties of the reservoir and the market prices of equipment and services. Therefore, variations in any one of these inputs can lead to significant variation in the costs of CO2 storage. Allowing for reasonable variations in all the inputs together in a Monte Carlo simulation of any particular site, then a large range of total CO2 storage costs is possible. The effect of uncertainty for the hypothetical representative storage site is illustrated.The impact of storing other gases together with CO2 is analysed. These gases include methane, hydrogen sulphide, nitrogen, nitrous oxides and oxides of sulphur, all of which potentially could be captured together with CO2. The effect on storage costs when varying quantities of other gases are injected with the CO2 is shown.Based on the CO2 storage cost estimates and the published costs capturing CO2 from industrial processes, the economics are shown of combined capture and storage (that is, the sequestration process as a whole) for the major CO2 generation sites across Australia combined with potential compatible storage sites. Examples are shown of the volumes of CO2 that could be sequestered economically depending on the level of the carbon credit in a hypothetical carbon credit trading regime. Purely as an illustration, assuming hypothetically that a real carbon credit of US$50 per tonne applied and that the cost of capture was US$40 per tonne across the board, then preliminary indications are that, ignoring tax considerations, it would be economic to store about 180 million tonnes per year of CO2. This is equivalent to about 70% of the annual CO2 emissions from stationary sources in Australia in 2000.
PETROLEUM PROCESSING PLANTS—TECHNICAL SURVEILLANCE PROGRAM
Authors: Gibbeson J.M.
Published: August 2017

On behalf of itself and BHP-B, Esso operates offshore production platforms in Bass Strait, a crude stabilisation and gas processing plant at Longford and a LPG fractionation plant at Long Island Point, Victoria. The Technical Surveillance Program for these facilities is implemented at both the Operator and Engineering levels. The program has been enhanced by building on existing DCS process control and process information (PI) systems and through development of a more structured engineering monitoring system. The enhanced program continues to register tangible benefits in integrity, product quality, recovery, efficiency and reliability and capacity.At the operator level, the process is monitored continuously, assisted by process alarms to maintain the plant within the normal desirable operating zone. Safe operating limits define the outside boundary of the safe operating envelope which is secured with shutdown and other automatic protective devices. Alarm and limit conditions associated with these parameters have been incorporated into the DCS control system with pre-defined operator responses appearing automatically on the screen if the condition is reached.At the engineering level, the surveillance program is a systematic periodic monitoring process focussing on optimum performance and continuous improvement. It is structured using the elements of a management system. Within this framework, engineering spreadsheets have been developed with direct links to process data via process information system software. The spreadsheets assist plant engineers to efficiently monitor the key performance variables; they also pre-define the acceptable operating range, calculate statistical performance, highlight deviations and hyperlink back to the PI system for more detailed troubleshooting. Day-today deviations and performance improvements are fed back and reviewed at the working level, more significant issues are formally investigated and reviewed with management. Key data and overall performance is summarised monthly, and formally reviewed by plant and engineering management.
LEGAL DEVELOPMENTS IN 2002
Authors: Fahey J.
Published: August 2017

This paper briefly describes a number of key legal developments in 2002 of significance to the petroleum exploration, development and production industry.There have been a number of varied legal developments in this field during the past year and this paper is not an exhaustive account of all of them. It does, however, provide an overview of selected developments during 2002 which are noteworthy. In particular:developments in relation to the Timor Gap;native title developments (specifically the Ward and Yorta Yorta decisions);implications arising from the COAG Energy Markets Review; andvarious legislative developments.
THE CHALLENGES OF ENVIRONMENTAL MANAGEMENT IN 2003—A REVIEW OF REGULATORY, SUSTAINABILITY, AND MULTIPLE STAKEHOLDER INTEREST ISSUES
Authors: Pinceratto E.
Published: August 2017

Following the uncertainty created by the introduction of the EPBC Act in 2000, a new regime of public environmental assessment of petroleum projects was successfully established by the regulatory agencies and the petroleum industry.Sustainability of developments, multiple stakeholder interests and meaningful consultations, are the current challenges in accessing new areas for exploration and development.
EASTERN AUSTRALIA'S GAS SUPPLY
AND DEMAND BALANCE
Authors: Dickson A. , Noble K.
Published: August 2017

Concerns have been raised about the capacity for Australia’s natural gas supplies to keep pace with growing demand, particularly in eastern Australia. Specifically, it has been suggested that unless significant infrastructure investment is undertaken now the demand/supply balance situation in eastern Australia will deteriorate quickly as natural gas resources are depleted in the face of strongly growing demand.The purpose of this study is to examine whether and when supplies in eastern Australia are likely to fall short of growing demand.A modelling framework was developed by ABARE to examine these issues at a regional level, building on ABARE’s MARKAL model of the Australian energy system. The modelling framework includes representations of potential sources of natural gas and coal seam methane in Australia by basin, existing and proposed pipeline options and regional gas demands. A number of alternative supply side assumptions were also examined to evaluate their impact on the final results, including annual production rates from various basins and the availability of commercial and non-commercial reserves.
THE DEVELOPMENT OF THE GREATER GORGON GAS FIELDS
Authors: Oen P.M.
Published: August 2017

The vast reservoirs of untapped natural gas found in the Greater Gorgon area off Western Australia’s Pilbara coast contain in excess of 11 billion cubic metres (40 trillion cubic feet) of gas, representing some 25% of Australia’s total known gas resources. Developing this world-class resource is a matter of national importance as it would secure Australia’s position as a leading gas producer and provide a huge new source of wealth for both Australia and Western Australia.The key to unlocking the Greater Gorgon reserves is the development of the Gorgon field—one of the largest single gas fields ever discovered in Australia. Establishment of gas processing infrastructure on Barrow Island—which lies between the gas field and the mainland—would provide a catalyst for the future development of other Greater Gorgon area fields. Gas would be processed at that facility and transported through a gas pipeline to shore, enabling large new competitive supplies of gas to be delivered to the mainland.While the development of Gorgon gas would bring significant benefits—A$11 billion investment, A$17 billion in Commonwealth and State taxes and royalties and an annual increase in the nation’s export income of A$2.5 billion—the Gorgon gas field presents some unique challenges. With little associated liquid hydrocarbons, development costs must be kept to a minimum to maintain commercial viability. In addition, Gorgon gas contains a relatively high content of carbon dioxide (CO2) which results in substantial treatment cost and relatively large potential greenhouse gas emissions.Barrow Island—both an internationally important nature reserve and Australia’s largest operating onshore oilfield—has emerged as the development location that would enable gas from the Gorgon gas fields to be competitive in today’s market. The Western Australian Government has said the Gorgon venture (ChevronTexaco, Shell and ExxonMobil) must demonstrate at a strategic level that the proposed Gorgon gas development on Barrow Island can generate economic and social benefits, provide net conservation benefits and mitigate potential on-site impacts.
HYDROCARBON GENERATION AND EXPULSION FROM EARLY CRETACEOUS SOURCE ROCKS IN THE BROWSE BASIN, NORTH WEST SHELF, AUSTRALIA: A SMALL ANGLE NEUTRON SCATTERING STUDY
Authors: Radlinski A.P. , Kennard J.M. , Edwards D.S. , Hinde A.L. , Davenport R.
Published: August 2017

Small Angle Neutron Scattering (SANS) analyses were carried out on 165 potential source rocks of Late Jurassic–Early Cretaceous age from nine wells in the Browse Basin (Adele–1, Argus–1, Brecknock South–1, Brewster–1A, Carbine–1, Crux–1, Dinichthys–1, Gorgonichthys–1 and Titanichthys–1). Samples from Brewster–1A and Dinichthys–1 were also analysed using the Ultra Small Angle Neutron Scattering (USANS) technique.The SANS/USANS data detect the presence of generated bitumen and mobile hydrocarbons in pores and are pore-size specific. As the pore-size range in mudstones extends from about 0.001–30 μm, the presence of bitumen in the small pores detected by SANS indicates the depth of onset of hydrocarbon generation, whereas the presence of bitumen and mobile hydrocarbons in the largest pores detected by USANS indicates a significant saturation and the onset of expulsion.Although geochemical data imply the existence of a potential gas and oil source rock in the Lower Cretaceous section (Echuca Shoals and Jamieson Formations), the SANS/USANS data indicate significant generation but little or no expulsion. This source limitation may explain poor exploration success for liquid hydrocarbons in the area. The SANS/USANS data provide evidence of intra- and inter-formational hydrocarbon migration or kerogen kinetics barriers. There is no evidence of an oil charge to the Berriasian Brewster Sandstone from the Echuca Shoals Formation, although some gas charge in Brewster–1A is possible. This novel microstructural technique can be used to independently calibrate and refine source rock generation/expulsion scenarios derived from geochemistry modelling.
SEDIMENT SUPPLY TO THE GIPPSLAND BASIN FROM THERMAL HISTORY ANALYSIS: CONSTRAINTS ON EMPEROR—GOLDEN BEACH RESERVOIR COMPOSITION
Authors: Weber U.D. , Hill K.C. , Brown R.W. , Gallagher K. , Kohn B.P. , Gleadow A.J.W. , Foster D.A.
Published: August 2017

The Emperor and Golden Beach Subgroups are becoming the focus of Gippsland Basin exploration, yet little is known about their composition and distribution. Regional modelling of over 400 apatite fission track analyses in the hinterland constrains the timing, magnitude and distribution of uplift and denudation and hence sediment supply to the basin. The study yielded regional maps through time of palaeotemperature, overburden, denudation rate and palaeotopography, with increasing assumptions and hence uncertainty.Regionally the >60,000 km3 of Strzelecki Group comprises ~90% volcanoclastic detritus and coal with only ~10% basement-derived sediment, but the northern margin of the basin, near Lakes Entrance, is likely to have a higher basement-derived portion resulting in better reservoirs. The basement-derived sediments are probably largely granitic as the Devonian granites were exposed during the Permo-Triassic Hunter-Bowen Orogeny. Regional mid-Cretaceous uplift resulted in increased denudation of basement, but inversion of the basin margins resulted in denudation of the onshore Strzelecki Group sediments. Emperor and Golden Beach Subgroup sediments deposited in the subsiding Central Graben were at least 50% basement-derived, again with higher quality reservoirs predicted near the Lakes Entrance area and poorer reservoirs near to Wilson’s Promontory. The Latrobe Group siliciclastics were at least 80% derived from basement with a substantial portion from northern Tasmania and the Furneaux Islands around 60-50 Ma.