bluuebunny/crossref_metadata_2025 huggingface dataset:
EFFICIENT 3-D METHODS FOR OIL EXPLORATION
Authors: Einarsson D. , McBeath R. , Wardell J.
Published: August 2017

Since their beginnings in the mid-1970s, 3-D seismic surveys have been used in conjunction with development drilling for hydrocarbon production. When Detail 3-D data were available, there was little further use for the 2-D data collected earlier for prospect delineation and drilling of a wildcat well. The 2-D data collected in the exploration stage was nearly always on a grid.The Exploration 3-D method is applicable at this same stage, but it is based on collecting a suite of parallel lines; not grids. These lines can be spaced up to four times the spacing used for Detail 3-D surveys, which makes collection costs comparable to 2-D grid programs. After performing stack on the wider-spaced lines, an intelligent interpolation process is used to recover data at closer line spacings. These data are then suitable for 3-D migration. Compared to 2-D, Exploration 3-D data are migrated to true subsurface positions and times, and become the basis for interpretation as a 3-D data volume.Exploration 3-D provides a framework of data that is consistent with all 3-D requirements. Should the Exploration 3-D data not provide the resolution needed for development purposes, additional data can be collected by infill between the original lines, but they are used again for migration of the more detailed data set.
THE ROMA TO BRISBANE PIPELINE — MEETING AN EXPANDING MARKET
Authors: Elkington P.A.
Published: August 2017

The 440 km Roma to Brisbane gas pipeline has provided a reliable supply of natural gas to Brisbane since March 1969. In those 18 years it has carried approximately 4.8 billion m8 of gas from fields in the Roma and Surat regions.Initially installed as a free-flow 10 inch gas pipeline, the system has been considerably upgraded over time. As market demand in Brisbane has increased, Associated Pipelines Limited (APL) has met this demand by gradually increasing compression along the pipeline. An outline of the approach to compression, its installation and impact on deliverability as well as the operating philosophy is discussed.The gas pipeline has six mainline compressors installed and the capacity of the original pipeline has almost doubled to approximately 65 TJ/D. The sixth compressor was planned to be the final stage of APL's pipeline capacity expansion via compression.The alternatives available to increase capacity in the future are also examined. These alternatives include peak shaving, higher degrees of compression, looping and a new pipeline. The advantages and disadvantages of each alternative are outlined. Looping is the most practical alternative. The factors involved in selecting a looping program which can be tailored to meet market demand, are discussed.
COMPUTER MODEL SIMPLIFIES GAS FIELD PRODUCTION FORECASTING AND DEVELOPMENT PLANNING
Authors: Stork R.B.
Published: August 2017

Production forecasting of gas fields with complex gathering systems and facilities can be a daunting task. Each individual well and reservoir has its own characteristics which, when combined with connecting pipework and production equipment, creates a highly interrelated network. To obtain meaningful results from reservoir studies, gathering system or production facilities design, the simulation of each segment must be integrated in such a manner that gas flows and pressures are balanced at each node. With the use of a computer model, the task of matching gas well deliverability and production facilities is made easier for gas fields in the Surat/Bowen Basin and Denison Trough.The computer model takes a rigorous approach to gas field deliverability by simultaneously considering a nodal analysis of all reservoirs, wells, piping, compressors, and gas plants. By subjecting the total system description to a calculation procedure that integrates the various components, the influence of a modification to any one component is properly taken into account throughout the entire system. Consequently, variations in line sizing and loops, compressors, infield drilling, and combinations of these can be fully evaluated and optimised.Accurate simulation results are achieved for Surat Basin gas fields by performing comprehensive field pressure surveys of the gathering system and by history matching previous years' production. The model accepts a description of the development strategy for the field so it can selectively commission compressors and tie-in new wells in order to meet projected sales contracts. The result is a complete simulation of the gas field including a calculated schedule for future development which is essential to evaluate the economic feasibility of different field development scenarios.
SURFACE CASING DESIGN CONSIDERATIONS WITH EMPHASIS ON THE BASS BASIN
Authors: Winchester P.H.
Published: August 2017

The main purpose of surface casing and the associated blowout preventer (BOP) system is to contain any well pressure that may be encountered while drilling to total depth or the next casing depth. Not only does this mean that the casing and BOP should be sufficient to withstand the pressure exerted upon them, but also the depth of the casing shoe should be such that the formation will not break down under the influence of this pressure. The latter condition could lead to an internal blowout and subsequent cratering to surface.Design consideration for surface casing must encompass fracture propagation theory, pore pressure and kick volume estimates, and associated casing pressure calculations. A worked example from the Bass Basin gives a safe and effective design when these are applied.These design considerations also have an impact on the procedures for pressure testing casing, BOP, and formation which are valid when compared with the existing statutory requirements of Australia, Norway and the USA.Although the operator is responsible for correct casing design, the various statutory bodies have a role to technically challenge and modify drilling and casing programs, and the procedures outlined give the foundations on which to build an acceptable casing scheme.
THE APPLICATION OF MICROBIOLOGICALLY ENHANCED OIL RECOVERY TO THE ALTON FIELD, QUEENSLAND, AUSTRALIA
Authors: Towler B.F. , Bubela B.
Published: August 2017

The Alton Field has produced 1.875 million stock tank barrels of oil and is nearing the end of its primary life. It is proposed to enhance the recovery from the field microbiologically. Surfactant producing bacteria will be injected into the reservoir in order to lower the oil/water interfacial tension and mobilise the remaining oil. Laboratory experiments on artifical cores have demonstrated the viability of this process. This MEOR project will initially be done in a one-well cyclic Huff and Puff program.
GEOLOGICAL AND RESERVOIR ENGINEERING CONSIDERATIONS FOR THE NORTH RANKIN GAS RECYCLING PROJECT
Authors: Barker C. , Vincent P.
Published: August 2017

The North Rankin Field, situated in the Dampier Sub-basin offshore north-western Australia, is being developed as part of the North West Shelf Development Project. Substantial excess production capacity from the field exists until liquified natural gas exports to Japan plateau in late 1993. A recycling project was proposed to utilise this spare capacity. Gas produced in excess of current sales volumes is stripped of its condensate, and the lean gas is reinjected into the reservoir thereby increasing condensate production and the total recovery.The North Rankin A Gas Recycling Project was commissioned in June 1987 and its performance to date has been better than original expectations. The average recycling rate during the first few months of operation was approximately 13 x 106sm3/d (450 MMscfd) with associated condensate production of 1600 m3/d (10,000 STB/d). Studies suggest that the total recycled volume for the project, up until late 1993, may be in the order of 19 x 109sm3 (0.7 Tcf) with additional condensate recovery of approximately 2 million cubic metres (13 MMSTB).The design and implementation of subsurface aspects of the recycling project required close co-operation between the geological and reservoir engineering disciplines. Detailed studies were undertaken to determine reservoir extent and communication within the field in order to identify likely paths for lateral and vertical gas movement. Estimates of swept reservoir volumes were used to determine injected lean gas distributions. These gas distributions, in conjunction with operational aspects, formed the basis for the production and injection policy developed to maximise sweep efficiency and optimise condensate recovery from the recycling project.Multiple zone through tubing perforation was needed in most injection wells. The initial perforation was performed with an optimal underbalance pressure. Subsequent perforation was neutrally balanced. The degree of underbalance while perforating has a significant effect on perforation efficiency and simple models were used to predict this.Accurate estimates of well injectivity must be made to ensure that the perforation design allows well target rates to be met. Numerical reservoir and wellbore models were constructed to evaluate well injection potentials and gas distributions.To verify the design procedures and well performance, well testing and production logging was carried out before and after the start up of gas recycling. Production logging surveys in the injection wells and measuring condensate gas ratios in the producers are essential in monitoring the performance of gas recycling.
A STRATIGRAPHIC ANALYSIS OF THE TALGEBERRY OILFIELD
Authors: Torkington J. , Micenko M.I.
Published: August 2017

ATP 299P(2) is located in the south-west Queensland portion of the Jurassic Cretaceous Eromanga Basin. Exploration drilling within the permit has resulted in the discovery of several oil pools which are stratigraphically controlled. Appraisal drilling at the Talgeberry Oilfield demonstrated this point when Talgeberry-2, drilled at a structurally higher location, failed to encounter either of the producing sands in Talgeberry-1. Oil is currently being produced from the Wyandra Sandstone and Birkhead Formation in Talgeberry-1 and from the Murta Member in Talgeberry-2.Depositional models are presented for each of the producing reservoirs at the Talgeberry Field, based upon dipmeter interpretation. An integrated seismic stratigraphic study was also undertaken on the Birkhead Formation reservoir.Oil production at Talgeberry is currently confined to distributary channel sands or near-shore distributary mouth bar sands. Distal facies of the distributary mouth bar have been intersected and, while containing oil, have been found to be generally tight.Dipmeter interpretation has proven valuable in determining depositional environment but is limited in defining the a real extent of the reservoir. Seismic-stratigraphic studies are able to define the reservoir geometry better and lead to a more comprehensive understanding of the depositonal environment.
FACIES MODELS IN EXPLORATION — THE CARBONATE PLATFORMS OF NORTH-EAST AUSTRALIA
Authors: Davies Peter J. , Symonds Philip A. , Feary David A. , gram Christopher J. Pi
Published: August 2017

The carbonate platforms of north-east Australia encapsulate a record of tectonic, eustatic, climatic and oceanographic dynamism that has controlled their formation. Collectively, the Great Barrier Reef and the Queensland and Marion Plateaus, together with the rift basins that separate them, define a new model for carbonate platform evolution with important exploration consequences. Cretaceous rifting, Paleocene breakup, Cainozoic northward drift with concomitant climatic changes, Neogene subsidence pulses, and sea-level perturbations have combined to produce tropical carbonate platforms overlying temperate, mixed carbonate/siliciclastic facies. The Great Barrier Reef tropical shelf platform thins to the south; reefs first developed in the north in the Early to Middle Miocene along the west- to east-trending distal margin of a foreland basin. The reefs of the Queensland and Marion Plateaus developed in the Middle Miocene and are the precursors of the carbonate platforms of the central and southern Great Barrier Reef. The Miocene Marion Plateau barrier and platform reefs backstepped to become the Plio-Pleistocene Great Barrier Reef. Three energy- and climate-related carbonate facies associations define new prospecting scenarios: the tropical, high energy reef model; the tropical, low energy, Halimeda bioherm model; and the subtropical, low energy, deep water, red algal/ foram/bryozoan bioherm model. These facies occur within four distinct structural/sedimentological associations: the progradative platform margin, the backstepped platform margin, the foreland basin, and the fault block association. The models can be readily applied to the Gulf of Papua/Torres Shelf and the Canning Basin and may produce exciting new insights into carbonate plays in these areas.
THE SEARCH FOR STRATIGRAPHIC TRAPS IN THE SOUTHERN PATCHAWARRA TROUGH, SOUTH AUSTRALIA
Authors: Stanmore P.J. , Johnstone E.M.
Published: August 2017

A seismic stratigraphic study of the Early Permian Patchawarra Formation has been undertaken to delineate zones of reservoir sandstone development and to identify stratigraphic hydrocarbon traps in the western Patchawarra Trough region. In this intracratonic basinal setting, the Patchawarra Formation is dominated by paludal and lacustrine sediments with fluvial sandstones. The Patchawarra Formation in the Patchawarra Trough is a prolific, liquids-rich gas producer with discovered-in-place resources approaching 28 x 109 cubic metres (1 TCF).With minimal well control in the study area, seismically defined increments of strata (SIS units) have been mapped areally away from nearby fields. The occurrence of sand-prone facies has been predicted through the development of a palaeogeographic model for each unit.Integration of facies and structural maps has led to the identification of a suite of intraformational and basin edge stratigraphic plays.
APPLICATION OF THE DETACHMENT MODEL FOR CONTINENTAL EXTENSION TO HYDROCARBON EXPLORATION IN EXTENSIONAL BASINS
Authors: Etheridge M.A. , Symonds P.A. , Powell T.G.
Published: August 2017

The extension of the continental lithosphere that gives rise to continental rifts and eventually to passive continental margins and their basins is considered generally to involve shear on one or more major, shallow dipping normal faults (detachments). The operation of these detachments induces a basic asymmetry into the extensional terrane that is analogous to that in thrust terranes. As a result, the two sides of a continental rift and conjugate passive margin segments are predicted to have contrasting structure, facies development, subsidence history and thermal evolution.The major structural consequence of the detachment model is that half-graben rather than full graben geometry is expected in rift basins, consistent with recent interpretations in a wide range of continental rifts and passive margins. Half-graben geometry dominates in the Bass Strait basins, the Canning Basin and in a number of Proterozoic rifts, and has been observed on most parts of the Australian continental margin. Variations in the along-strike geometry of extensional basins are accommodated by transfer faults or fault zones. Transfer faults are as important and widespread in rifts as the classical normal faults, and they have important consequences for hydrocarbon exploration (e.g. design of seismic surveys, structural interpretation of seismic data, play and leav development).The fundam* nal asymmetry of extensional basins, and their compartmentalisation by transfer faults also control to a large extent the distribution of both source and reservoir facies. A model for facies distribution in a typical rift basin is presented, together with its implications for the prime locations of juxtaposed sources and reservoirs. Maturation of synrift source rocks depends on both the regional heat flow history and the amount of post-rift subsidence (and therefore burial). Both of these factors are influenced, and are partly predictable by the detachment model. In particular, there may be substantial horizontal offset of both the maximum thermal anomaly and the locus of post-rift subsidence from the rift basin. Analysis of deep crustal geophysical data may aid in the interpretation of detachment geometry and, therefore, of the gross distribution of thermal and subsidence histories.
THE PLEASANT CREEK ARCH, ADAVALE BASIN, A MID DEVONIAN TO MID CARBONIFEROUS THRUST SYSTEM
Authors: Remus David , Tindale Karen
Published: August 2017

Interpretation of recently acquired multifold seismic data has led to a reappraisal of the structural evolution of the Adavale Basin with particular reference to the Pleasant Creek Arch.The Basin initially formed as a back arc basin to the west of the Anakie/Nebine volcanic arc. Three stages of tectonic evolution are recognised; rifting, extension and convergence. The Pleasant Creek Arch represents a foreland fold belt cratonward of the major convergent margin deformational zone.The model proposed for the development of the Pleasant Creek Arch is a buried to weakly emergent foreland thrust system modified by Late Carboniferous erosion. This was subsequently covered by sediments of the Galilee and Eromanga Basins. Late to Middle Devonian sediments are involved in thrusting that exhibits two styles of deformation. Along the southern 70 km of the thrust front Lower to Middle Devonian sediments are thrust under an upper decollement forming a passive roof duplex or backthrust zone. The Boree Salt acts as this upper decollement. The thrust tipline is controlled by the western depositional edge of the salt. North of this area the thrust appears to have been weakly emergent. Proprietary and open file seismic data from ATP's 301P, 304P and 305P and surrounding permits are used to illustrate the model. Comparisons can be made between this model and similar thrust systems in the Canadian Rocky and Mackenzie Mountains, the Appalachian Plateau, the Southern Norwegian Caledonides, the Kirthar and Sulaiman Mountain ranges of Pakistan and the Papua New Guinea fold belt.
THE INFLUENCE OF STRUCTURAL GROWTH AND OTHER FACTORS ON THE CONFIGURATION OF FLUVIATILE SANDSTONES, PERMIAN COOPER BASIN
Authors: Stuart W.J. , Kennedy S. , Thomas A.D.
Published: August 2017

The term structural growth is applied to subtle earth movements contemporaneous with sediment accumulation. To assess this factor, one must consider the roles of lateral sandstone accretion, river avulsion and sediment dispersal in the context of basin setting, climate and geological time.Interpretation of stratigraphic relationships and isopach and structural maps of areas comprising structural highs in the subsurface of the Permian Cooper Basin is based on the correlation of thin chronostratigraphic units in the Patchawarra Formation (Tirrawarra Field) and the Toolachee Formation (Big Lake-Moomba fields). Unit C of the Toolachee Formation in the Moomba area comprises several fining upwards sequences that appear cyclic and sheet-like. This facies relationship is similar to those in the immediate downflank areas of Big Lake. However, upflank in crestal areas, fluviatile sequences are more typical of multistorey sandstones. These crestal sandstones are the result of structural growth contemporaneous with deposition from a fluviatile meandering system during a significant interval of geological time. Meandering river systems are considered to have crossed the Big Lake-Moomba area locally from south-west to north-east. Isopach and percentage sandstone maps indicate that streams preferred an avenue of transport towards the Nappamerri Trough.Stratigraphic analysis of Patchawarra Formation Unit 2B in the Tirrawarra Field suggests a slightly greater rate of local subsidence there than in Big Lake and Moomba fields, resulting in a decreasing sand body interconnection. Although occasional fining upward sequences correlate across the field area, multistorey sandstone development occurs in an arcuate belt on its western side. This is the result of local structural growth and faulting contemporaneous with fluviatile deposition. Potential petroleum reservoirs of fluviatile origin occur in numerous basins worldwide. In basins exhibiting low rates of differential subsidence, potential reservoirs and seals occur as sheet-like bodies in structural traps near the margins of major depocentres. Knowledge of local and basinal differential subsidence and fluviatile architecture provides confidence for field exploitation and exploration for new plays.
PALAEOZOIC TECTONICS, AMADEUS BASIN, CENTRAL AUSTRALIA
Authors: Bradshaw J.D. , Evans P.R.
Published: August 2017

The Amadeus Basin is divided into a number of structural provinces that developed during the Palaeozoic Alice Springs Orogeny, the course of which is described in terms of: Early Palaeozoic preorogenic crustal extension and basin development; Late Ordovician-Carboniferous NE-SW compressional orogenesis; and Late Carboniferous-(?)Early Permian NW-SE compression.The Southern Province is composed largely of Proterozoic formations that had been deformed during the Petermann Ranges Orogeny. The Central Anticlinal Province is a shear zone of four en echelon trends. The Parana Hills and Mereenie trends have a left lateral orientation to each other and formed during the first phase of orogenesis; the Gardiner Range and James Range trends are right lateral and formed during the second stage. Structures in the Northern Province were created by decollement within the evaporite-bearing Bitter Springs Formation and, to a lesser extent, in the Cambrian Chandler Formation, and by collapse of the basin fill under the burden of the Brewer Conglomerate in a style similar to the formation of diapirs along the northern front of the Pyrenees. The MacDonnell Homocline is a mountain front tip line that resembles the Triangle Zone of the Canadian Rocky Mountains. The Allambi Thrust Zone separates the Northern Province from the Camel Flat Platform that bears diapiric salt walls derived from the Chandler Formation.The varying stress field and revised time scale for orogeny may be of significance to evaluation of reservoir fracture patterns and source rock maturation curves.
STUDIES ON PETROLEUM GEOLOGY AND GEOCHEMISTRY, MIDDLE PROTEROZOIC, McARTHUR BASIN NORTHERN AUSTRALIA I: PETROLEUM POTENTIAL
Authors: Jackson J- , Sweet I. P. , Powell T. G.
Published: August 2017

Mature, rich, potential source beds and adjacent potential reservoir beds exist in the Middle Proterozoic sequence (1400-1800 Ma) of the McArthur Basin. The McArthur and Nathan Groups consist mainly of evaporitic and stromatolitic cherty dolostones interbedded with dolomitic siltstone and shale. They were deposited in interfingering marginal marine, lacustrine and fluvial environments. Lacustrine dolomitic siltstones form potential source beds, while potential reservoirs include vuggy brecciated carbonates associated with penecontemporaneous faulting and rare coarse-grained clastics. In contrast, the younger Roper Group consists of quartz arenite, siltstone and shale that occur in more uniform facies deposited in a stable marine setting. Both source and reservoir units are laterally extensive (over 200 km).Five potential source rocks at various stages of maturity have been discovered. Two of these source rocks, the lacustrine Barney Creek Formation in the McArthur Group and the marine Velkerri Formation in the Roper Group, compare favourably in thickness and potential with rich demonstrated source rocks in major oil-producing provinces. There is abundant evidence of migration of hydrocarbons at many stratigraphic levels. The geology and reservoir characteristics of the sediments in combination with the distribution of potential source beds, timing of hydrocarbon generation, evidence for migration and chances of preservation have been used to rank the prospectivity of the various stratigraphic units in different parts of the basin.
THE USE OF PLANT DERIVED BIOMARKERS FOR CORRELATION OF OILS WITH SOURCE ROCKS IN THE COOPER/EROMANGA BASIN SYSTEM, AUSTRALIA
Authors: Alexander R. , Larcher A.V. , Kagi R.I. , Price P.L.
Published: August 2017

Whether or not the sediments in the Eromanga Basin have generated petroleum is a problem of considerable commercial importance which remains contentious as it has not yet been resolved unequivocally. Sediments of the underlying Cooper Basin were deposited throughout the Permian and much of the Triassic, and deposition in the overlying Eromanga Basin commenced in the Early Jurassic and extended into the Cretaceous. As Araucariaceae (trees of the kauri pine group) assumed prominence for the first time in the Early to Middle Jurassic and were all but absent in older sediments, a promising approach would seem to be using the presence or absence of specific araucariacean chemical marker signatures as a means of distinguishing oils formed from source rocks in the Eromanga Basin from those derived from the underlying Cooper Basin sediments.The saturated and aromatic hydrocarbon compositions of the sediment extracts from the Cooper and Eromanga Basins have been examined to identify the distinctive fossil hydrocarbon markers derived from such resins. Sediments from the Eromanga Basin, which contain abundant micro-fossil remains of the araucariacean plants, contain diterpane hydrocarbons and aromatic hydrocarbons which bear a strong relationship to natural products in modern members of the Araucariaceae. Sediments from the Permo-Triassic Cooper Basin, which predate the Jurassic araucariacean flora, have different distributions of diterpane biomarkers and aromatic hydrocarbons.Many oils found in the Cooper/Eromanga region do not have the biological marker signatures of the Jurassic sediments and appear to be derived from the underlying Permian sediments; however, several oils contained in Jurassic to Cretaceous reservoirs show the araucariacean signature of the associated Jurassic to Early Cretaceous source rock sediments. It is likely, therefore, that these oils were sourced and reservoired within the Eromanga Basin and have not migrated from the Cooper Basin sequences below. Accordingly, exploration strategies in the Cooper Eromanga system should include prospects that could have been charged with oil from mature Jurassic/Early Cretaceous sediments of the Eromanga Basin.
RECENT TRENDS IN PROJECT FINANCE FOR THE OIL AND GAS INDUSTRY
Authors: Henschke M.
Published: August 2017

The oil and gas industry has gone through an extremely difficult period in the last two years. The decline in crude oil prices of early 1986 caused great uncertainty concerning the future of the industry. As those uncertainties receded, the October 1987 collapse in equity markets resulted in new volatility in financial markets for all industries.Growth and innovation in capital markets in recent years have resulted in a broader range of alternatives for funding of project financings being available to a wider range of companies. Increased competition among banks has also impacted the costs of borrowing. Overall, the benefits for borrowers are increased flexibility and lower costs of funds.Project finance for the oil and gas industry is as important a tool as ever. From both borrowers' and lenders' viewpoints, its traditional elements of project assessment, and design and structuring of facilities are perhaps more important than ever. New approaches to risk mitigation are continually being sought. From a borrower's viewpoint, an important factor is the ability of banks to understand technical aspects of the industry and the elements of risk involved in new and existing projects.
CRUDE OIL MARKETING DEREGULATION
Authors: Savage T.M.
Published: August 2017

The Australian Government's decision to deregulate indigenous crude oil marketing from 1 January 1988 brings to an end the period of the Government's involvement in this area of the petroleum industry. The determination of price, the development and monitoring of administrative procedures to ensure equitable allocation of indigenous crude, and the resolution of differing views between producers, refiners and marketers were all areas where Government was actively involved. While the extent of future involvement is uncertain, the policy changes put a different dimension on exploration and production efforts for all companies and on their relationship with the marketplace, both locally and overseas.The move to deregulation widens the available options for all parties - producers, refiner/ marketers and international traders. WTiile these options exist, the most probable situation in 1988 is not expected to be greatly different from that which has existed in the last couple of years. No refineries will be shut down; product imports will increase slightly but not significantly enough to affect total demand on Australian refineries. A reduced level of indigenous crude should be run to enable greater flexibility in crude/feedstock selection for optimising refinery profitability. However, at least 75 per cent of indigenous production should be continued to be absorbed within Australia with the bulk of the exports being made from Gippsland and Jabiru areas.The change in emphasis towards product excise has ensured that the Australian Government has the mechanism to sustain revenue, essentially independent of the prices obtained for indigenous crude. As such, the Government's involvement in crude oil marketing, if at all, will be significantly reduced.Factors affecting negotiations between producers and other interested parties have been explored. It is considered that, although it is highly unlikely that firm markets will have been established by early 1988, a workable set of arrangements will have been developed to ensure that crude oil production is moved. As many uncertainties will exist on the validity of these arrangements for the long term, there will be a tendency towards spot or short-term sales agreements so that the options are left open. The key pricing points are seen to be the value BP Australia is prepared to pay for Western Australia and Queensland production, at Kwinana and Brisbane respectively, and the prices being obtained by Esso/BHP for Gippsland crude in the export market.
A TECTONOSTRATIGRAPHIC FRAMEWORK FOR THE VULCAN GRABEN, TIMOR SEA REGION
Authors: Pattillo J. , Nicholls P.J.
Published: August 2017

The Vulcan Graben is a northeast trending intracratonic rift system developed in response to Late Jurassic-Early Cretaceous break-up of the Australian northwest continental margin. A depositional sequence study was undertaken of the Vulcan Graben and the surrounding area, incorporating regional well and seismic data. From this a tectonostratigraphic framework has been established. Three megasequences are defined in relation to the Callovian rift episode; Pre-rift (pre-Callovian), Syn-rift (Callovian to Valanginian) and Post-rift (Valanginian to Present Day), each consisting of a number of discrete depositional sequences. This study has clarified the structural and stratigraphic evolution of the region, enabling development of dynamic depositional models. These models constrain the vertical and lateral facies distribution across the region, thus providing a powerful basis for petroleum exploration, including prediction of reservoir, seal and source rocks.Significantly, while Late Jurassic rifting was initiated in the Late Callovian, imprinting a NE-SW oriented grain, a second major tectonic episode occurred in the Kimmeridgian trending ENE-WSW, which generated the dominant regional structural architecture. Recognition of this Kimmeridgian event has considerable impact on the successful delineation of structural plays within the region and provided significant control on syn-rift facies distribution and consequently stratigraphic play potential within the Vulcan Graben. Stratigraphic and structural relationships clearly indicate that rifting ceased in the middle Valanginian, followed by post- rift thermal subsidence and consequent transgression and inundation of the Vulcan Graben. The intra-Valanginian event represents a regional disconformity rather than a major tectonic unconformity and defines the boundary between the syn- and post-rift megasequences. This is consistent with the revised Valanginian date for the onset of sea-floor spreading in the Argo Abyssal Plain.A revised lithostratigraphic nomenclature is proposed for the region which complements the resolution achieved by depositional sequence mapping.
EXPLORATION POTENTIAL OF THE TIMOR GAP ZONE OF CO-OPERATION
Authors: Botten Peter , Wulff Keiran
Published: August 2017

The area covered by the Zone of Co-operation (ZOC) in the eastern Timor Sea represents the last large area of sparsely explored continental shelf around Australia that has obvious potential for significant hydrocarbon accumulations.Extravagant claims about the assumed exploration potential of the area have been widely published in Australia and Indonesia. The low level of exploration within the Zone does not allow confident prediction of potential at this time. Only five wells and less than 20 000 km of seismic are present in the ZOC. A similar level of exploration had been reached in the Ashmore-Cartier area in the western Timor Sea by 1972. With such a small data base, extrapolation of conclusions drawn from exploration of adjacent areas is fundamental to the present evaluation.Many technical comparisons can be made between the ZOC and the heavily explored Ashmore-Cartier area. Evaluation of data within the ZOC and extrapolation of important information from other parts of the Timor Sea indicates that all the prerequisites for hydrocarbon accumulations exist within the area.Jurassic reservoirs sealed by the Cretaceous Bathurst Island Formation provide the primary reservoir objectives in all areas of the ZOC away from the Malita Graben. Oil recovered in wells situated on the Londonderry High has been correlated with mature source rocks of the Jurassic Plover Formation in the Sahul Syncline. This depocentre is concluded to have the capacity of generating both oil and gas for potential accumulations in the southern and western part of the ZOC. The capacity of the Malita Graben to source major volumes of hydrocarbons from potential source rocks of the Flamingo Group is still to be established. Insufficient information is available to reliably predict the distribution of oil and gas in the ZOC.Play types similar to those seen in the Ashmore-Cartier area are present in the ZOC. Fault-controlled horst plays, typified by the Jabiru Field, are prevalent on the Sahul Platform. Upper Cretaceous sandstone plays dominate the southern part of the ZOC where reservoir objectives in the Jurassic Plover Formation and Flamingo Group are considered to be too deep for economic exploration.Application of some of the exploration lessons learnt in the western Timor Sea is essential to future activities in the ZOC in order to minimise possible discovery costs.
SOUTHERN GEORGINA BASIN: A NEW PERSPECTIVE
Authors: Lodwick W.R. , Lindsay J.F.
Published: August 2017

The Georgina Basin formed as a shallow intracratonic depression on the Australian craton along with a number of other basins in the Proterozoic and early Palaeozoic, probably in response to the break up of the Proterozoic supercontinent. Since all of these basins evolved under similar tectonic and sea-level controls, the basins all have similar sediment successions and, it might thus be assumed, similar petroleum prospectivity. One basin, the Amadeus Basin, currently has petroleum production, suggesting a potential for exploration success in the other intracratonic basins.In the Amadeus Basin the main petroleum prospects lie within or adjacent to major sub-basins that formed along the Basin's northern margin. The Georgina Basin has sub-basins that formed along its southern margin, almost as a mirror image of the Amadeus Basin. The lower Palaeozoic section of the Toko Syncline in the southern Georgina Basin has hydrocarbon shows in Middle Cambrian to Middle Ordovician rocks. Source rocks appear to have developed within the transgressive systems tract and the condensed interval of the highstand systems tract, at times when the basin was starved for clastic sediments and carbonate production was restricted.Seismic data acquired in the 1988 survey are of a higher quality than that previously obtained in the area. Its interpretation portrays the westward thrusting French Fault at the eastern edge of the Toko Syncline with potential hangingwall and footwall traps. Cambro- Ordovician Georgina Basin sediments subcrop the overlying Eromanga Basin with angularity, providing potentially large stratigraphic traps. Fracturing of the Cambrian and Ordovician carbonates within fault zones, and solution porosity at the unconformity, would also enhance reservoir potential in the area. Perhaps most significantly, the new data also shows an earlier, apparently independent basin completely buried beneath the Georgina section. The concealed section may simply be a very thick, early Upper Proterozoic section, or perhaps an equivalent to, or a lateral extension of the McArthur Basin. Recent work in the McArthur Basin has shown considerable source potential in the McArthur and Roper Groups, which may support the possibility of an additional, as yet unrecognised, source beneath the Georgina Basin.
STRATIGRAPHY AND PETROLEUM POTENTIAL OF THE ONSHORE CARPENTARIA BASIN, QUEENSLAND
Authors: McConachie B.A. , Filatoff J. , Senapati N.
Published: August 2017

Over the past four years Comalco in joint venture with Bridge Oil have undertaken extensive exploration within the Carpentaria Basin. Over 3000 km of multifold reflection seismic data has been acquired and four petroleum exploration wells were drilled. In addition, the Queensland Department of Mines (GSQ) has drilled four cored full-section stratigraphic wells in the deeper parts of the basin.Analysis of the work to date indicates that the basin is not as structurally simple as first thought. Four sub- basins are recognised based on the composition and timing of Mesozoic sedimentary fill. These are the Weipa, Western Gulf, Staaten and Boomarra sub-basins. The Boomarra Sub-basin contains a Middle Triassic red-bed sequence which is 250 m thick in drill hole GSQ Dobbyn- 1. Thick, Middle Jurassic-Lower Cretaceous, basal fluvial and marine sandstone sequences are restricted to the Weipa and Staaten sub-basins, where they are confined principally to the palaeotopographic valleys. The Western Gulf Sub-basin is believed to contain minimal basal Mesozoic sandstone.Although sedimentary depositional environments exhibit widespread continuity throughout the Carpentaria Basin, variations in lithology and provenance as well as diachronism can be demonstrated between the various sub-basins. Most notably the late Neocomian marine transgression began earlier at Weipa than in the southern sub-basins. A basin-wide stratigraphy has been developed from deep drill hole correlations and mapping of outcrop sections around the margin of the basin in the Olive River, Gregory Range and Melish Park areas thus enabling the petroleum reservoir character of the basin to be determined.
THE EXPLORATION AND APPRAISAL HISTORY OF THE SKUA FIELD, AC /P2 - TIMOR SEA.
Authors: Osborne M.
Published: August 2017

The discovery of the Skua Field resulted from an extended and aggressive exploration program with major emphasis placed on gaining continual improvements in seismic data quality. Improved seismic data was principally responsible for the accurate delineation of the Swift and Skua structures which resulted in the drilling of the Skua-2 discovery well in 1985.A positive analysis of the results of Skua-2 (which clipped the fault bounded edge of the field) coupled with extensive new seismic acquisition and further seismic data quality improvements encouraged the AC/P2 Joint Venture to drill the field confirmation well Skua-3, in 1987.The appraisal stage of the Skua field included three further wells and was designed to investigate several specific problem areas: the modest structural size, the volume of a small associated gas cap, the presence of steeply dipping reservoir strata of interbedded sands and shales, and the effect of discrete zones of intense velocity anomaly.A major consideration has been to achieve a balance between exploration expenditure and the need to attain a thorough understanding of the complex field geology to reduce the uncertainties associated with the problem areas.The only potentially viable development option for Skua is to use subsea completions and a floating production facility (FPF). BHP Petroleum's engineering expertise and history of FPF developments at Jabiru and Challis is of great importance to successfully developing this smaller, more complex field.
AUSTRALIA'S DEEPWATER FRONTIER PETROLEUM BASINS AND PLAY TYPES
Authors: Falvey D. A. , Symonds P.A. , Colwell J.B. , Willcox J.B. , Marshall J.F. , Williamson P.E. , Stagg H.M.J.
Published: August 2017

Vast areas of Australia's continental margin sedimentary basins lying seawards of the 200 m water depth line, or shelf edge, are under-explored for petroleum. Indeed, most are essentially unexplored. However, recent advances in drilling and production technology, as well as recent reconnaissance seismic, geochemical, geothermal and seabed sampling data collected by the Bureau of Mineral Resources' (BMR) Marine Division, may reduce the perceived economic risk of many of these deepwater basins relative to their shelf counterparts. Triassic reefs have been identified off the northern Exmouth Plateau and possibly in the deepwater Canning Basin, locally within a predicted oil window. In the deepwater North Perth Basin, major wrench structures have been identified. The deepwater areas of the Great Australian Bight and Otway Basin are actually the main depocentres of a major basin complex lying along the almost totally unexplored southern Australian continental margin. The Latrobe Group in the outer Gippsland Basin is likely to have similar geology to the well explored and productive shelf basin, but remains untested. The Queensland and Townsville troughs, in deepwater off northeast Australia, contain many significant structures typical of unbreached rift systems.All these areas have been risked relative to each other and their prospectivity assessed. The most attractive frontier areas in terms of relative risk may be the Otway and North Perth basins. The highest potential may occur in the deepwater rift troughs off northeast Australia, although the relative risk is very high. Triassic reefs of the Northwest Shelf may have the best prospectivity in the shorter term, given that they are known from drilling in a region with proven source potential and a substantial exploration infrastructure.
BASS STRAIT DRILLING - PREPARING FOR THE NINETIES
Authors: Lake B. D. , Santostefano V.
Published: August 2017

Future development drilling in Bass Strait will be challenged by small field sizes, thin oil columns and increasing drilling difficulty due to greater hole angle and reach. New drilling technology successfully introduced in the recent Bream, Whiting, Perch and Dolphin developments including Steerable Drilling Systems (SDS), Polycrystalline Diamond Compact (PDC) bits and Logging While Drilling (LWD) tools, coupled with the successful use of jackup rigs for miniplatform development, has given Esso the tools and confidence to meet the development challenges of the 'nineties. Bass Strait's first horizontal well has been successfully drilled and completed with further wells planned in the current Bream development. There still remain some areas requiring improvements, including hole cleaning in high angle holes. Improvements in this and other areas will further improve drilling capability.Given the right incentives Bass Strait drilling technology is well positioned for the challenge of oil development in the 'nineties.
FORMATION EVALUATION IN HIGHLY-DEVIATED, LONG REACH DEVELOPMENT WELLS ON THE NORTH RANKIN GAS FIELD, NW SHELF, AUSTRALIA
Authors: Lasserre D.
Published: August 2017

A large proportion of the North West Shelf development gas wells are long reach (greater than 3500 m) and highly deviated. For reservoir description and management purposes, comprehensive formation evaluation needs to be carried out in these wells.Considerable difficulties have been encountered with electric log data acquisition due to friction and borehole conditions in these long, highly-deviated wells. As a result, new techniques to log the zones of interest were introduced. A system using the drill pipe to transport the downhole logging tools has been successfully used.Also, low-toxicity oil-based mud (LTM) was introduced in order to ease drilling problems and borehole conditions. However, owing to the non-conductive nature of the oil-based drilling fluid, improvements were required in the vertical resolution of the resistivity measurements and the estimation of the formation porosity.A computer program using a forward deconvolution technique recently developed by Shell's research laboratory in Holland has been successfully applied to enhance the vertical resolution of the resistivity log reading.The large range of uncertainty on the pore volume has been reduced to reasonable level by calibrating the porosity log data against core data obtained in a well drilled with LTM.
THREE-DIMENSIONAL GEOLOGICAL MODELLING IN THE KINGFISH AND WEST KINGFISH OIL FIELDS: THE METHOD AND APPLICATIONS
Authors: Mudge W. J. , Thomson A. B.
Published: August 2017

RESMAP is an Exxon proprietary program that makes possible the building of three-dimensional geological models. The models consist of millions of tabular cells contained within a stratigraphic framework. The models are generated by the integration of log analysis, seismic interpretation and the geologist's well picks and interpretation.RESMAP models are easy to access for generating structural and stratigraphic geological cross-sections. Maps such as structure, top of porosity and net sand percentage can be generated as well as subcrop and supercrop maps. Hydrocarbon-in-place estimates are also made from the model.The Kingfish and West Kingfish fields each possess a complex stratigraphic framework and exhibit rapid facies changes in the nearshore marine sediments. Techniques available in RESMAP enable the integration of the well data and seismic maps to produce an accurate stratigraphic framework containing the geometries of truncation onlap and downlap. The interpolation of porosity data from the wells successfully captures the facies distribution. This is due to the excellent well spacing in the vicinity of the facies changes and the ability to place geological constraints on the interpolation.The model provides a valuable communication tool for the mass of data present in a field. The model can also be updated quickly upon receipt of new data, providing a dynamic reservoir description on which to base future field management.