bluuebunny/crossref_metadata_2025 huggingface dataset:
STRUCTURAL-STRATIGRAPHIC DEVELOPMENT OF THE GIDGEALPA-MERRIMELIA-INNAMINCKA TREND WITH IMPLICATIONS FOR PETROLEUM TRAP STYLES, COOPER BASIN, AUSTRALIA
Authors: Apak S.N. , Stuart W.J. , Lemon N.M.
Published: August 2017

A successful approach to basin analysis requires the broad-scale reconstruction of the three dimensional depositional systems in relation to concurrent structural development of the basin. The Gidgealpa-Merrimelia-lnnamincka (GMI) Trend is a prominent, asymmetric, mildly compressional anticlinal trend located in the Late Carboniferous to Triassic Cooper Basin. Its northwest flank is controlled by high angle thrust faults which were reactivated repeatedly throughout geological time. The present study addresses both the structural style and depositional character of the GMI Trend, focusing on selected areas. It is an integrated approach utilising wire-line logs, seismic interpretation, isopach and structural maps and detailed palynology. This approach has produced a detailed chronostratigraphic subdivision of the Permo-Triassic sequence, particularly the Patchawarra Formation, which points to evidence of synsedimentary tectonics. Evidence from crestal unconformities suggests that the GMI Trend was uplifted during at least four distinct structural episodes. These phases of uplift result from the rejuvenation of pre-Permian faults. Regional investigation of chronostratigraphic units incorporating palynological information, clearly demonstrates the palaeogeography and the presence of internal unconformities within the Patchawarra Formation. Subsurface distribution of hydrocarbon pools and improved definition of areas of prospectivity relate to the episodic uplifts. Although known hydrocarbon reserves have largely accumulated in structural traps, additional potential exploration targets in the Permian sequence exist in stratigraphic, combination, pinchout and downflank fault traps as well as onlap plays along the mid flank areas of the GMI Trend.
RESERVOIR POTENTIAL OF THE CATHERINE SANDSTONE, DENISON TROUGH, EAST-CENTRAL QUEENSLAND
Authors: John B.H. , Fielding C.R.
Published: August 2017

The Denison Trough is a deep elongate sub-basin, located along the western margin of the Permian and Triassic Bowen Basin in east-central Queensland. Gas is produced commercially from several small fields in the area, mainly from the Aldebaran Sandstone. The Catherine Sandstone, a Late Permian unit lying in the central part of the Trough, has produced gas in a limited number of petroleum wells, but is generally not a primary target for exploration. This paper aims to provide a stratigraphic and sedimentological framework for the formation, and to develop ideas relevant to its future exploration potential. Data are derived from measured outcrop sections and from cored intersections of the unit in stratigraphic bores and petroleum wells. Facies analysis has identified fluvial channel, lagoon, tidal inlet, shoreface to foreshore, offshore-transition and offshore depositional environments. The overall depositional setting has been interpreted as a wave-dominated coastline cut by fluvial channels, and passing basinward into an open marine shelf. Analysis of geometry and petrophysical characteristics suggests that tidal inlet facies and high-energy shoreface subfacies have the greatest reservoir potential within the Catherine Sandstone. Both are best developed in the northern half of the Denison Trough; gas production from the Catherine Sandstone in the area has been derived exclusively from intervals of high-energy shoreface subfacies. Further potential from these rocks is suggested, with the Catherine Sandstone and equivalents providing exploration targets of the future.
DEPOSITIONAL SYSTEMS AND SEQUENCE STRATIGRAPHY OF THE CRETACEOUS WARNBRO GROUP, VLAMING SUB-BASIN, WESTERN AUSTRALIA
Authors: Spring D.E. , Newell N.A.
Published: August 2017

Petroleum exploration of the Vlaming Sub-basin (offshore Perth Basin) has to date primarily focussed on targets sealed by the shale facies of the Early Cretaceous Warnbro Group, a predominantly marine succession. The Warnbro Group is formally sub-divided into the Gage Sandstone Member (base), South Perth Shale and Leederville Formation (top). However, owing to diachroneity between lithofacies, adherence to the formal nomenclature has rendered the prediction of shale facies at specific locations unreliable, resulting in a number of invalid exploration tests.To resolve this problem, sequence and seismic stratigraphic concepts have been used within exploration permit WA-221-P to provide a framework for a new stratigraphic model for the Warnbro Group. Seven depositional sequences have been identified.The model recognises that palaeogeography during Warnbro Group deposition was largely governed by tectonism associated with the Neocomian break-up event which produced a complex assemblage of fluvio-deltaic, shelfal and submarine fan systems. Sequence boundary development can be related to phases of tectonism following the Neocomian break-up as well as to eustatic fluctuations, while variations in base-level, subsidence rate, sediment supply, basin physiography and a basinwide marine transgression primarily control the environments of deposition and their spatial distribution.The model has enabled the lithofacies of the Warnbro Group to be assigned to a predictable succession of associated systems tracts, providing a practical approach to understanding the distribution and geometries of Warnbro Group reservoir and seal facies within the Vlaming Sub-basin.
EXPLORATION RESULTS, HYDROCARBON POTENTIAL AND FUTURE STRATEGIES FOR THE NORTHERN GALILEE BASIN
Authors: Hawkins P.J. , Green P.M.
Published: August 2017

Exploration activity in the northern Galilee Basin has been sporadic and is still at an immature stage. Recent geological investigations by the Queensland Department of Resource Industries have brought about a better understanding of the geological setting and stratigraphic evolution of the basin. These investigations also identified key source and reservoir units, determined maturation trends and delineated areas with hydrocarbon potential. The geological results indicate that the Aramac Coal Measures and Betts Creek beds contain the most favourable source and reservoir rocks. Thermal modelling of vitrinite reflectance data suggests that various parts of the basin reached maturity for hydrocarbon generation at different times. Integration of the geological results and thermal modelling has enabled exploration concepts to be developed for the basin. Application of these concepts has highlighted areas along the western margin of the Koburra Trough and eastern Maneroo Platform, and areas adjacent to the Cork Fault and the Wetherby Structure in the Lovelle Depression that warrant further exploration.
RESERVOIR MANAGEMENT OF SUBSEA DEVELOPMENT FIELDS IN THE TIMOR SEA
Authors: Chapman G.J.
Published: August 2017

In a subsea development, downhole survey costs are high but the reservoir management requirements are basically the same as those for fields developed onshore or by a platform. This paper describes techniques employed to monitor reservoir performance of a field with a subsea style development, primarily by the utilisation of surface data, supplemented by selected downhole data. Along with a number of field examples, from the Timor Sea, a case study of the recently commissioned Skua Field is presented which demonstrates these techniques and how they were applied to enable effective reservoir management of this subsea development. These techniques include the determination of reservoir pressures, reservoir communication and changing well productivities using surface pressures to evaluate the extent of aquifer support. This data is supported by analytical and numerical reservoir studies to provide an understanding of reservoir performance and to facilitate the continuous development requirements of a producing field and to optimise the recovery of reserves.
THE FATE OF HYDROCARBONS ASSOCIATED WITH DRILLING FROM THE NORTH RANKIN 'A' GAS AND CONDENSATE PLATFORM, WESTERN AUSTRALIA.
Authors: Chegwidden A. , Fisher S.J. , Alexander R. , Kagi R.I.
Published: August 2017

Drilling operations from the North Rankin 'A' platform ceased in August 1991. At that time two sets of triplicate samples of seabed sediments for hydrocarbon analysis were collected using a remotely operated vehicle. One set of sediments was collected along a transect up to 10 km from the platform in the direction of the prevailing current; the other was collected along a perpendicular transect to a distance of 1.2 km. The total hydrocarbon concentrations of these samples were 75 000 mg/kg (dry weight of sediments) beside the platform, decreasing rapidly with distance from the platform. At approximately 800 m in the direction of the current levels were 40 mg/kg, and at approximately 2000 m the concentrations found were 2 mg/kg.Detailed examination revealed the presence of aromatic hydrocarbons in the sediments. This indicates that they must be derived, at least in part, from formation fluids; however, a substantial contribution from the low toxicity base oil (hydrogenated kerosene) component of drilling fluids is present, judging from the molecular weight distribution of the sediment hydrocarbons.Near the cuttings chute samples contained approximately five per cent aromatic hydrocarbons. Beyond approximately 400 m in the direction of the prevailing current, and along the perpendicular transect, aromatic hydrocarbons made up approximately 20 per cent of the sediment hydrocarbons. As the distance from the cuttings chute increased, the extent of biodegradation of the hydrocarbons in the sample also was found to increase.
SUSTAINABLE DEVELOPMENT AND EXPLORATION
Authors: Fisher Brian S. , Tulpule Vivek , Bowen Bruce
Published: August 2017

The environment, defined broadly to include both reproducible and natural resources, such as petroleum reserves and wildlife parks, supports all economic and other social activity. The notion of sustainable development arises from a concern that future well-being could be eroded by the pursuit of economic goals which degrade and deplete finite resources.While such concerns are not new, the focus of debate has shifted within the past twenty years. Following the first oil price shock in the early 1970s, questions about whether or not it is possible to maintain growth while energy stocks are declining were brought to the fore. In recent years, however, concerns about the possible negative impact of exploration activity and fossil fuel use on the natural environment — also considered a finite resource — have gained prominence.But achieving sustainable resource use involves making trade-offs. For example, open access to a highly prospective site to help meet the energy needs of current and future generations has to be weighed against the site being partially or fully closed to exploration in order to completely preserve the value of the natural environment inherent in the site.To answer questions about environmental tradeoffs requires judgments about the relative social values of alternative uses of the sites in question. Information based on commercial exploration assists in making such judgments. By upgrading knowledge about the economic and social value of a natural resource, the information gained from exploration can help with making judgments about sustaining or conserving the human environment for future generations. Indeed, because the outcome of the exploration process has both social and commercial implications, it is likely that the level of exploration activities chosen for purely commercial reasons may be lower than the level that would be considered optimal if full account were taken of the trade-offs inherent in maintaining or improving the quality of life of future generations.The purpose in this paper is to investigate the role that exploration can play in improving economic and social well-being generally. To do this, petroleum exploration activity is separated into two phases — first, 'low impact' exploration such as the collection of seismic data and, second, drilling. The key contribution of this paper is to highlight conditions under which levels of low impact exploration, as determined by commercial considerations alone, are likely to be less than the socially optimal level.
PLANNING AND DRILLING OF SINUOUS HORIZONTAL WELLS FOR THE GRIFFIN AREA DEVELOPMENT
Authors: Berean D. , Slate T. , Wallace T. , Aldred R. , Hedger L. , Mills P. , Cowley. R.
Published: August 2017

The Griffin Area Development in the Barrow Sub-basin of Western Australia consists of three major oil fields, the Griffin, Scindian and Chinook fields.One of many new concepts of subsea technology used for the Griffin Area Development is the application of horizontal wells with a sinuous profile to improve oil recovery in the Birdrong reservoir.Reservoir simulation modelling initiated the concept and as a result, a multi-disciplined team was formed early in the pre-development phase to plan and implement a horizontal drilling program. Issues which were addressed by this team during planning included wellbore stability, drilling fluids, liner and completion design, wellpath orientation, reservoir constraints and formation evaluation techniques.After an extensive planning period, three sinuous path horizontal wells, Griffin-5(H), Griffin-6/ST1(H) and Scindian-2/STI(H) were successfully drilled in early 1993 by a semi-submersible rig as part of the Griffin/Scindian fields development drilling program.These sinuous wells have a well path profile which intersects the reservoir in three low-angle passes of the vertical section over a horizontal length of between 800 and 950 m, in the shape of a sine wave.A feature of the wells was the use of geosteering techniques to keep the sinuous profile on track to intersect specific reservoir targets, using the latest in formation evaluation measurement while drilling (FEMWD) technology.Although technically successful, the economic benefit of the horizontal wells will be measured by their production performance when tied into the 'Griffin Venture' floating production facility, expected on stream in early 1994.
TRIALS OF A MULTIPHASE FLOW METER ON PRODUCTION PIPELINES FROM OIL WELLS
Authors: Roach G.J. , Watt J.S. , Zastawny H.W. , Hartley P.E. , Ellis W.K.
Published: August 2017

This paper describes trials of a new multiphase flow meter (MFM) on the Vicksburg offshore production platform and at the oil processing facilities on Thevenard Island. The flow meter is based on two specialised gamma-ray transmission gauges mounted on a pipe carrying the full flow of oil, water and gas.Two MFMs were used in both trials, one mounted on a vertical (up flow), and the other on a horizontal, section of a pipeline linking the test manifold to the test separator. Measurements were made on flows of oil/water/gas mixtures from each well, and on combined flows of different pairs of wells.The r.m.s. difference between the flow rates determined by the MFM and by the separator output meter was determined by least squares regression. For the Vicksburg trial, the ratio of r.m.s. difference and mean flow rate was 8.9 per cent for oil, 5.6 per cent for water, 5.2 per cent for liquids, and 8.2 per cent for gas for flows in the vertical pipeline and slightly larger for flows in the horizontal pipeline. For the Thevenard Island trial, the preliminary results for flows in the vertical pipeline show the ratio to be 6.8 per cent for oil, 6.0 per cent for water, 3.4 per cent for liquids, and 5.9 per cent for water cut.
BHP PETROLEUM'S NEW TECHNOLOGY METHANOL RESEARCH PLANT
Authors: Rees I.
Published: August 2017

BHP Petroleum (BHPP) is in the process of constructing a 164 tonne per day Methanol Research Plant (MRP) on the outskirts of Melbourne. The plant is designed to demonstrate and develop the Leading Concept Methanol (LCM) technology of ICI Katalco. The plant will be the first large scale demonstration of this technology and is part of BHPP's strategy to develop viable options for the development of Australia's uncommitted gas resources. The strategy is to demonstrate and develop the LCM technology onshore and then to apply the technology to an offshore production environment.The LCM technology as applied to the MRP involves a new synthesis gas generation process and other features which result in a compact plant design with low utilities requirements and insensivity to vessel motion effects.Although the MRP is being built primarily for Research and Development (R&D) it has been sized consistent with future scale up to world scale methanol capacity. The plant capacity is sufficient to supply a major share of Australia's methanol demand, particularly that of the immediate vicinity in Victoria.The construction of the plant started in April, 1993 and is currently about 85 per cent complete and on schedule. Final mechanical completion is scheduled for mid 1994 with commissioning in the third quarter. The capital cost of the project is approximately A$70 million.
REHABILITATION OF OFFSHORE BASED EMPLOYEES-A COST EFFECTIVE APPROACH
Authors: Gillett Robert J.
Published: August 2017

This paper will outline the experience of a cost effective rehabilitation policy for Offshore based workers. Woodside Injury Management Program focuses on Early Intervention and Alternative Duties as strategies.This approach has enabled Woodside to reduce the average cost of Offshore based employees' Workers' Compensation claims from $26 993 in 1986 to $6 043 in 1992.The number of days lost have been reduced from 61.1 days per lost time claim in 1986 to 26.2 days in 1992.
FLOATING PRODUCTION, STORAGE AND OFFLOADING FACILITIES—IMPACT OF THE NEW OIL TANKER CONSTRUCTION RULES
Authors: Gehling Robin C. , Lane Michael P. , Thornton Robert M.
Published: August 2017

FPSOs are often converted from, and carry ship safety certification as, oil tankers. The two types of ship have been reasonably compatible until passage in early 1992 of new international requirements for tankers to be constructed or converted to double hull requirements and for existing vessels to be phased out when they have been in service for 25 to 30 years. Such requirements, which have become increasingly onerous since 1973, are based on the hazards involved in navigation of oil tankers and do not reflect the risks applying to FPSO operations.In cooperation with the Australian offshore industry, AMSA made a number of submissions to the International Maritime Organisation (IMO), seeking clarification on whether FPSOs should be subjected to the rules for oil tankers. To cover the possibility that it is confirmed that FPSOs should comply with the rules, the submission proposed modifications to those rules to reflect the FPSO operating environment.The submissions resulted in IMO deciding, in March 1993, that although FPSOs would continue to be treated as oil tankers, they would not be required to comply with the double hull requirements which could have necessitated their withdrawal from service upon reaching 30 years of age.Achievement of a successful conclusion to this project has involved a cooperative effort between AMSA and the offshore oil and gas industry.
PYROLYSIS OF AROMATIC COMPOUNDS AS A GUIDE TO SYNTHETIC REACTIONS IN SEDIMENTS
Authors: Smith J. W. , George S. C. , Batts B. D.
Published: August 2017

The syntheses of methylaromatics by the reactions of phenanthrene, anthracene and pyrene with coals and CH4 at 220°C to 400°C is demonstrated. At temperatures not exceeding 350°C the experimental conditions may be thermally equated, in terms of R0 values, to those approximating the oil window. Therefore, the high degree of methylation achieved, the insensitivity of the methylation process to reaction conditions and the systematic and theoretically predictable increases with temperature in the ratio of the ß/α substituted methyl isomers of the parent aromatic hydrocarbon, provide support for significant geosynthetic processes in sediments. The high concentration of n-alkanes generated from the coal may play a crucial role in reactions.
EXPLICATING A GUT FEEL-BENCHMARKING THE CHANCE FOR EXPLORATION SUCCESS
Authors: Goldstein Barry A.
Published: August 2017

"In labouring to be brief I become obscure"—Horace. There is a 50-50 chance for adequate trap, seal, source, reservoir, and the likelihood for oil. So, the probability for a successful oil-find is three per cent. Brief and to the point? Yes. Comparable to other estimates? Frequently, not. Obscure? Yes.A check-list of 33 enquiries is offered as a yardstick for measuring the adequacy of petroleum prospect factor conditions. Each of the enquiries is a part of an overall test that good prospects should pass. Application of the check-list results in probability assignments to the chance for commercial exploration success. The length of the check-list for factor assessment may, at first, appear daunting for what experienced explorationists commonly regard as a simple and quick risk assessment task. However, a thorough approach introduces an essential element of uniformity between prospect evaluations. The proposed approach goes to some length to explicate consequential judgements that otherwise may remain unrecorded.Examples of the application of this method are provided for three prospects in distinctive Australian basin settings. Two of these prospects have been drilled, Nebo ?1 (oil discovery in the offshore Beagle Sub-basin) and Roswin North ?1 (gas discovery in the Bowen Basin). The third feature, the Galapagos prospect in the offshore southern Browse Basin, remains to be drilled.Subjective ratings of factor adequacy based on analogy are an essential exploration planning tool. Numerical expressions of the chance for successful exploration are routinely, and subjectively based on analogy to successful play-types. Successful models are the yardsticks used to measure the favourability of juxtaposed conditions that combine to define the likelihood that petroleum has been generated, migrated and trapped in reservoirs, and can be exploited at a profit. Subjective ratings (of exploration-factors) often remain implicit and obscure. Inconsistency between prospect assessments can result.Standards can be set not only to ensure that subjective assessments of exploration prospects are to a large degree comparable, but also to explicitly demonstrate that no relevant criteria have been the subject of neglect in the prospect assessment process. Indeed, expansion into new ventures with finite exploration budgets is incentive to formalise the prospect risk assessment process, no matter how reputable and well experienced are the available expert opinions.These guide-lines are offered as a basis to:reduce subjectivity in judging the relative certainty of play-type ingredients;boost internal consistency between exploration prospect assessments;provide an explicit basis for exploration assessment training; andGain management's confidence. Risk assessment is rigorous and 'seen-to-be-done'.The check-list will also be valuable in farm-in and farm-out discussions. Buyers and sellers are offered some common-ground to mould perceptions.
THE EFFECTS OF OVERPRESSURE, LITHOLOGY, CHEMISTRY AND HEATING RATE ON VITRINITE REFLECTANCE EVOLUTION, AND ITS RELATIONSHIP WITH OIL GENERATION
Authors: Khorasani Ganjavar Khavari , Michelsen Johan K
Published: August 2017

Overpressure has been regarded by several authors to retard vitrinite reflectance evolution. The previously presented data regarding overpressure, however, are inconclusive because the covariation between burial rate, fluid pressures and heating rate has been overlooked. The present results show that the thermal effect of overpressure in shales has no important influence on the observed relationship between temperature and reflectance. The pressure acting on vitrinite and other solid organic matter is mainly lithostatic, and the influence of overpressure on the confining pressure of vitrinite is negligible. The apparent relationship between vitrinite reflectance and lithology is closely linked with important differences in the chemistry of vitrinites. Systematic differences in the reflectance of vitrinites in coals and interbedded shales are associated with variations in the concentration of lignin-derived products in the source organic matter, and their state of biochemical/chemical modifications governed by the depositional conditions. Vitrinite reflectance is related to both the transformation ratio and the molecular structural organisation of the vitrinite. In immature vitrinites subjected to intermediate to high heating rates, the ultrafine textural heterogeneity is enhanced, retarding the reflectance increase, compared to those heated at low rates, for the same change in transformation ratio. There exists a small but systematic difference between the heating-rate dependency of vitrinite reflectance versus heating-rate dependency of oil generation.To reflect the slow evolution of reflectance through the zone of extensive oil generation, kinetic models for predicting reflectance employ wide activation energy distributions. Due to this intrinsic property, it is simple to calibrate or predict reflectance, but the use of reflectance for predicting oil generation or calibration of thermal models has a low precision, with a wide range of solutions with equally good fits.
HYDROCARBON PROSPECTIVITY OF THE TORQUAY SUB-BASIN, OFFSHORE VICTORIA
Authors: Trupp Mark A. , Spence Keith W. , Gidding Michael J.
Published: August 2017

The Torquay Sub-basin lies to the south of Port Phillip Bay in Victoria. It has two main tectonic elements; a Basin Deep area which is flanked to the southeast by the shallower Snail Terrace. It is bounded by the Otway Ranges to the northwest and shallow basement elsewhere. The stratigraphy of the area reflects the influence of two overlapping basins. The Lower Cretaceous section is equivalent to the Otway Group of the Otway Basin, whilst the Upper Cretaceous and Tertiary section is comparable with the Bass Basin stratigraphy.The Torquay Sub-basin apparently has all of the essential ingredients needed for successful hydrocarbon exploration. It has good reservoir-seal pairs, moderate structural deformation and probable source rocks in a deep kitchen. Four play types are recognised:Large Miocene age anticlines, similar to those in the Gippsland Basin, with an Eocene sandstone reservoir objective;The same reservoir in localised Oligocene anticlines associated with fault inversion;Possible Lower Cretaceous Eumeralla Formation sandstones in tilted fault blocks and faulted anticlines; andLower Cretaceous Crayfish Sub-group sandstones also in tilted fault block traps.Maturity modelling suggests that the Miocene anticlines post-date hydrocarbon generation. Poor reservoir potential and complex fault trap geometries downgrade the two Lower Cretaceous plays.The Oligocene play was tested by Wild Dog-1 which penetrated excellent Eocene age reservoir sands beneath a plastic shale seal, however, the well failed to encounter any hydrocarbons. Post-mortem analysis indicates the well tested a valid trap. The failure of the well is attributed to a lack of charge. Remaining exploration potential is limited to the deeper plays which have much greater risks associated with each play element.
THE INTEGRATION OF MODERN TECHNOLOGY IN GIPPSLAND'S CENTRAL FIELDS STUDY
Authors: P.V.Hinton P.V.Hinton , M.G.Cousins  , P.E.Symes
Published: August 2017

The central fields area of the Gippsland Basin, Australia, includes the Halibut, Cobia, Fortescue, and Mackerel oil fields. These large fields are mature with about 80% of the reserves produced. During 1991 and 1992 a multidisciplinary study, integrating the latest technology, was completed to help optimise the depletion of the remaining significant reserves.A grid of 4500 km of high resolution 3D seismic data covering 191 square kilometres allowed the identification of subtle structural traps as well as better definition of sandstone truncation edges which represent the ultimate drainage points. In addition, the latest techniques in seismic attribute analysis provided insight into depositional environments, seal potential and facies distribution. Sequence stratigraphic concepts were used in combination with seismic data to build complex multi million cell 3D geological models. Reservoir simulation models were then constructed to history match past production and to predict future field performance. Facility studies were also undertaken to optimise depletion strategies.The Central Fields Depletion Study has resulted in recommendations to further develop the fields with about 80 work-overs, 50 infill wells, reduction in separator pressures, and gas lift and water handling facility upgrades. These activities are expected to increase ultimate reserves and production. Some of the recommendations have been implemented with initial results of additional drilling on Mackerel increasing platform production from 22,000 BOPD to over 50,000 BOPD. An ongoing program of additional drilling from the four platforms is expected to continue for several years.
PETROLEUM POTENTIAL OF RAGAY GULF, SOUTHEAST LUZON, PHILIPPINES
Authors: Lee C.S. , Galloway M.C. , Willcox J.B. , Moore A.M.G. , Fraser A.R. , Heggie D.T. , Murray; A.P. , Apostol J.R.L. , Trinidad N.D. , Abando R.P. , Panganiban D.V. , Guazon E.B. , Cortez E.E. , Reyes E.N.
Published: August 2017

During March-May 1992, the Australian Geological Survey Organisation and the Philippine Department of Energy conducted a cooperative marine seismic and underway geochemical survey in four offshore Philippine basins which included Ragay Gulf. The project was funded and supported by the Australian International Development Assistance Bureau.The newly acquired and reprocessed seismic data from Ragay Gulf show a significant improvement in penetration and stratigraphic resolution. Seismic interpretation has revealed the existence of five sedimentary sub-basins with 2.5 – 6 seconds of Eocene to Recent sediments. Several potential traps have been evaluated for hydrocarbon reserves and new prospects are identified.No well has been drilled offshore in the Ragay Gulf. Onshore well log information and stratigraphy have assisted in the correlation and interpretation of offshore seismic data and allowed potential reservoirs to be recognised. The primary reservoir targets are the carbonate sequences of both Early and Late Miocene age. The widespread volcanoclastic sand may be an important secondary target, especially for gas reservoirs.Onshore and offshore geochemical data have confirmed the presence of mature source rocks from which generated hydrocarbons are currently migrating to the surface and, by inference, to reservoirs.A wide diversity of play types is recognised which could have been sourced from three separate source kitchens in the Bondoc, Ragay and Burlas Sub-basins. Specific entrapment possibilities are:Compressional fault-dependent traps (e.g. Anima Sola).Compressional anticlinal fault independent traps (e.g. Alibijaban and Palad).Late Miocene carbonate reefal buildups (e.g. Apud and Gorda).Early Miocene carbonate reservoirs in drape over highs (e.g. San Narciso and Bagulaya).
ENVIRONMENTAL MANAGEMENT SYSTEMS: A QUANTUM LEAP FORWARD OR NOTHING NEW FOR THE E&P INDUSTRY?
Authors: Wright R.A.D.
Published: August 2017

There has been a recent tendency for an increasingly sophisticated approach to managing the socalled 'soft' issues such as quality, occupational health, safety, and the environment which are of importance to modern business enterprises. Increasing sophistication brings with it new terminology which can often confuse rather than clarify. Environmental management systems are in vogue today as evidenced by standards organisations in many countries defining their recommendations. The purpose of this paper is to explain what is meant by environmental management systems and to demonstrate that they have in fact been in place for many years in the petroleum exploration and production industry.The first part of the paper will outline the purpose and importance of having a management system to assure environmental protection. The reasons for recent interest by regulators and standards organisations will also be explored. The essential elements of an environmental management system will then be described with examples of its application to the petroleum industry. Particular reference will be made to activities associated with the North West Shelf Gas Project which is operated by Woodside Offshore Petroleum.
OIL PRICE RISK MANAGEMENT IN THE 1990s—ISSUES FOR PRODUCERS AND LENDERS
Authors: Lambert Steve
Published: August 2017

Oil prices have exhibited considerable volatility over the past five or ten years and the management of oil price risk has become an important factor in underpinning the viability of many oil producing operations from both a lender's and investor's perspective. Various oil based hedging products are now available to protect against such volatility, ranging from products which fix forward prices to option based arrangements which set a floor price but retain some (or all) of the potential upside. These products have particular relevance for petroleum companies with limited financial resources or who are looking to limit recourse to particular assets/cashflows.There are a number of techniques which can be successfully combined to mitigate oil price volatility and the most relevant of these to a producer are discussed. The recent development of the Tapis swap and option markets, which have provided flexibility to Australasian producers, is also discussed.Oil based financial products can also be used as a method of funding (say for a development or acquisition) as an alternative to traditional cash based borrowing structures, thus creating a natural hedge against oil price movements. The use of such structures, coupled with a well structured revenue hedging program, can enhance a project's attractiveness from a lender's perspective (particularly with respect to protection against downside movements in oil price) and/or provide greater certainty of returns to producers.A case study of a recent commodity risk management based financing is presented which highlights many of the points discussed.
IS THERE LIFE AFTER LLOYDS?
Authors: Grierson W.N.
Published: August 2017

London is burning. Lloyds of London that is. The Society which could well be described as the 'Mecca' of energy insurance, is under fire. Record losses have been reported in each of the last three accounting years, and there does not appear to be any significant improvement in sight. Added to the Financial problems are the compounding difficulties of internal litigation, allegations of bad management, and a severely dented international trading reputation.The reasons for the current malaise at Lloyds are a combination of internal and external factors, contributed to by an unprecedented level of worldwide catastrophes certainly, but also the result of poor market practises and what could be regarded as an unsuitable business structure for the 1990s.Lloyds has however determined to meet the challenge and is in the process of implementing the most radical series of changes in its 306 year history. Measures to be introduced include isolation of old year liabilities from new, resolving ongoing problems with litigation and disputes amongst its membership, improving management, leadership, and business processes, reforming the hitherto sacred agency system, and restructuring the capital base of the organisation to amongst other things admit Corporate Members for the first time and manage underwriting capacity more effectively.Lloyds now wishes to be perceived as 'lean and focused' and has produced a global target profit for 1995 of £900 million, representing what most participants would consider a quite acceptable 33 per cent pre-tax return on funds at Lloyds for its individual Names and a 20 per cent pre-tax return for its Incorporated Members. At the same time it has pledged to reduce its own costs by £190 million and decrease its internal staff from 12 000 to 9 500 over the same period.The future of Lloyds and all of those who depend on her is however by no means assured. Significant impediments will have to be overcome if the new initiatives are to succeed, not the least of which is the resistance of a 300 year old institution to change and increased regulation.Opinion even in the City of London itself is clearly divided as to the potential for a successful recovery. The question remains, is there life after Lloyds?
THE STOKES GAS FIELD, SOUTHWEST QUEENSLAND
Authors: Bennett D.G. , Heath R.S. , Taylor S.
Published: August 2017

The Stokes gas field is located in South West Queensland permit ATP 259P, close to the South Australia/Queensland state border. It was discovered and successfully appraised by the Stokes-1,-2 and -3 wells drilled during 1993 and early 1994. Productive zones, with DST flow rates of up to 237 x 103m3/d, are present in the Early Permian Epsilon and Patchawarra formations with moderate gas liquids contents present in the higher reservoirs. A total net pay thickness of 63 m occurs in Stokes-2. Generally, reservoir quality is moderate to good with core permeabilities occasionally exceeding one darcy. Some low deliverability Patchawarra Formation reservoirs are present which contain greater than 20 per cent kaolin. These microporous reservoirs are characterised by low resistivity responses similar to that of water saturated reservoirs.The field's discovery coincided with the onset of renewed South West Queensland gas exploration. Seismic data were recorded in 1990 and 1992 to mature the Stokes prospect to drillable status. The structure had been recognised as being highly prospective due to its regional setting. Proved and probable gas-in-place exceeds 5.7 x 109 m3 which approximates the highside case estimated from pre-drill probabilistic reserves distributions.Comprehensive reservoir pressure data were obtained from each well and were instrumental in locating appraisal wells and demonstrating that reservoirs are filled to the structural spill point. The Stokes-3 results indicate that some fault compartmentalisation may occur suggesting a more complex structure than originally mapped. Isolation of other reservoirs may also occur between Stokes-1 and -2.
THE ELANG OIL DISCOVERY ESTABLISHES NEW OIL PROVINCE IN THE EASTERN TIMOR SEA (TIMOR GAP ZONE OF COOPERATION)
Authors: Young I. F. , Schmedje T.M. , Muir W.F.
Published: August 2017

The Elang-1 oil discovery in the Timor Gap Zone of Cooperation (ZOC) has established a new oil province in the eastern Timor Sea. The discovery well, completed in February 1994, recorded a flow of 5,800 BOPD (5,013 STBOPD) from marine sandstone of the Late Jurassic Montara beds. The oil is a light (56° API), undersaturated oil with a GOR of approximately 550 SCF/STB. Elang-1 was the first well drilled by the ZOCA 91-12 Joint Venture and only the fifth well in the ZOC since exploration of this frontier area resumed in 1992.The Elang Prospect, initially mapped by Petroz in the late 1970s on the basis of regional seismic data, was detailed by the 1992 Walet Seismic Survey. The prospect is the main crestal culmination on the Elang Trend, a prominent structural high to the north of the Flamingo High that was established during continental break-up in the Late Jurassic. The Elang Trend is bounded to the south by a series of en-echelon normal faults and connecting relay ramps and comprises a number of horst and tilted fault blocks.Elang-1 tested a near crestal culmination on the Elang Prospect and intersected a 76.5 m gross oil column below 3,006.5 m RT. At time of drilling this oil column was the thickest that had been encountered by any well in the Northern Bonaparte Basin. Good quality reservoir sandstone in six discrete bodies were intersected within the Montara beds. Core-measured porosity and permeability range up to 17 per cent and 2.2 Darcies within the oil column.Subsequent to the Elang discovery, the Joint Venture recorded a 402 km2 3D survey over the Elang Trend. Elang-2, an appraisal well spudded in September 1994 prior to receipt of the 3D data, established the lateral continuity of the Montara beds reservoirs. Flow rates of 6,080 BOPD (5,300 STBOPD) and 7,500 BOPD (5,970 STBOPD) from separate intervals have confirmed that high deliverabilities can be expected from individual sandstones. Further appraisal drilling is planned in the first half of 1995. This is expected to lead to commercial development of the field.
THE DIRKALA SOUTH OIL DISCOVERY: FOCUSSING ON COST-EFFICIENT RESERVOIR DELINEATION
Authors: Mackie S.I. , Gumley C.M.
Published: August 2017

The Dirkala Field is located in the southern Murta Block of PEL's 5 and 6 in the southern Cooper and Eromanga Basins. Excellent oil produc­tion from a single reservoir sandstone in the Juras­sic Birkhead Formation in Dirkala-1 had indicated a potentially larger resource than could be mapped volumetrically. The hypothesis that the resource was stratigraphically trapped led to the need to define the fluvial sand reservoir seismically and thereby prepare for future development.A small (16 km2) 3D seismic survey was acquired over the area in December 1992. The project was designed not only to evaluate the limits of the Birkhead sand but also to evaluate the cost effi­ciency of recording such small 3D surveys in the basin.Interpretation of the data set integrated with seismic modelling and seismic attribute analysis delineated a thin Birkhead fluvial channel sand reservoir. Geological pay mapping matched volu­metric estimates from production performance data. Structural mapping showed Dirkala-1 to be opti­mally placed and that no further development drill­ing was justifiable.Seismic characteristics comparable with those of the Dirkala-1 Birkhead reservoir were noted in another area of the survey beyond field limits. This led to the proposal to drill an exploration well, Dirkala South-1, which discovered a new oil pool in the Birkhead Formation. A post-well audit of the pre-drill modelling confirmed that the seismic response could be used to determine the presence of the Birkhead channel sand reservoir.The acquisition of the Dirkala-3D seismic survey demonstrated the feasibility of conducting small 3D seismic surveys to identify subtle stratigraphically trapped Eromanga Basin accumulations at lower cost and risk than appraisal/development drilling based on 2D seismic data.
ECONOMIC BENEFITS OF THE KUTUBU RESERVOIR MANAGEMENT STRATEGY
Authors: Magner T.N.
Published: August 2017

In spite of all the of the studies and analyses conducted since the initial oil discovery in 1986, considerable uncertainty existed over the expected performance of the Kutubu reservoirs prior to initial production. Extensive use of reservoir simulation during the field development helped overcome technical challenges in the development phase. Continued modelling work has increased understanding of reservoir behaviour, identified additional development opportunities and further enhanced field economics.Since First Oil in June 1992, over 100 MMSTB of light, sweet Kutubu crude oil have been produced and exported {through October 1994). At present, the field produces approximately 120,000 STBO/D from 27 vertical wells and two horizontal wells. Reservoir pressure maintenance is provided by gravity-stable re-injection of produced gas into five wells.On the whole, the reservoirs have met or exceeded expectations to date. This is in part due to the effective planning and implementation of a strategy to manage the Kutubu reservoirs. This reservoir management strategy combines an aggressive program of reservoir surveillance, data collection, computer simulation and continuous reassessment of previous assumptions.
PROBE PERMEABILITY STUDIES FOR BETTER RESERVOIR UNIT EVALUATION WITH EXAMPLES FROM THE TIRRAWARRA SANDSTONE, COOPER BASIN AND THE MURTA AND MCKINLAY MEMBERS, EROMANGA BASIN
Authors: Boult P. J. , Theologou P.N. , Johnson G. A. , Carbone M.
Published: August 2017

Probe permeametry studies have enabled a better understanding of permeability characteristics of three clastic reservoirs: The Tirrawarra Sandstone in the Tirrawarra and Gidgealpa fields of the Cooper Basin and the Murta and McKinlay Members in the Jena and Biala fields of the Eromanga Basin.An empirical relationship between Hassler-sleeve core plug measurements and probe permeametry is used for calibration. The probe permeameter takes sufficient non-destructive readings to define permeability better within an individual facies or reservoir flow unit.Frequency versus log (permeability) plots and semi-variograms allow visual comparison of individual reservoirs and facies. Histograms of plug and probe data show similar distributions, but the plug data generally have a lower variance than the probe data.For the Tirrawarra Sandstone there is a better match between probe permeability data and wireline predicted permeability than between the latter and core plug permeability.Azimuth directional permeability is evident for the braided fluvial sands of the Tirrawarra Sandstone. Permeability within the measured formations is primarily related to depositional facies. Secondary reduction in permeability within the Tirrawarra Sandstone is mainly due to ductile rock fragment compaction and authigenic clay precipitation with possible groundwater flow control in the Gidgealpa field.
SEISMIC DELINEATION OF STRUCTURE-CONTROLLED CARBONATE CEMENT AND POTENTIAL ECONOMIC IMPLICATIONS, ANGEL FIELD, NORTH WEST SHELF
Authors: Ryan-Grigor S. , Schulz-Rojahn J.P.
Published: August 2017

Major carbonate-cemented zones occur in Late Jurassic Angel Formation sandstones of marine mass flow origin that contain large hydrocarbon reserves in the Angel Field, Dampier Sub-basin. Preliminary results suggest that poikilotopic dolomite cement is dominant. The carbonate-cemented zones are identifiable from wireline log response and 3D seismic data, and occur in discrete intervals with a cumulative thickness of approximately 165m at Angel-2. These intervals produce a zone of high amplitude reflections of about 100 ms two-way time. Field-wide seismic mapping indicates that these carbonate-cemented zones sharply abut the northern margin of a major east-west trending strike-slip fault system that traverses this field. The carbonate-cemented zones extend in a wedge-like shape towards the northeast and concentrate along the crest of the main structural trend.The results underscore the importance of 3D seismic data for a better estimation of reservoir risk and reserves in variably carbonate-cemented sandstones.The carbonate-cemented zones may represent a 'plume' related to migration of petroleum and/or carbon dioxide. Therefore delineation of major carbonate-cemented zones using seismic data may aid in the identification of petroleum migration pathways and pools in the North West Shelf. Alternatively, carbonate cements dissolved south of the major fault zone and possibly in downdip locations in which case dissolution pores may exist in these areas. Further research is required to evaluate these hypotheses.