bluuebunny/crossref_metadata_2025 huggingface dataset:
STRUCTURAL INHERITANCE, STRESS ROTATION, OVERPRINTING AND COMPRESSIONAL REACTIVATION IN THE GIPPSLAND BASIN—TUNA 3D SEISMIC DATASET
Authors: Power M.R. , Hill K.C. , Hoffman N.
Published: August 2017

In the Tuna area, Turonian rifting between Australia and the Lord Howe Rise produced extensive irregular NE–SE to ENE–WSW trending Emperor Subgroup depocentres by oblique reactivation of inherited Early Cretaceous Strzelecki Group and Palaeozoic basement fault geometries. Santonian Tasman seafloor spreading rotated the stress vectors clockwise so that NE–SW Emperor Subgroup syn-rift depocentres were abandoned and more easterly trends were reactivated. This developed the Proto-Rosedale Fault across the northern margin as a complex series of branching fault splays with reactivated ENE–WSW trending segments and new east– west hard linkages. In the Late Cretaceous, extension vectors rotated a further 45o clockwise sympathetic to NW–SE trending Tasman Sea mid oceanic ridges. ENE– WSW trending splays of the Proto-Rosedale Fault became abandoned and overprinted by new Maastrichtian NW–SE trending segments perpendicular to the NE–SW stress field. By the Paleocene these segments had linked, displaying en echelon geometries above the obliquely reactivated Proto-Rosedale Fault. Tasman seafloor spreading and fault-controlled subsidence in Gippsland had finished by the Early Eocene. Extension was punctuated by Coniacian-Santonian, Eocene and Oligocene compressive pulses that inverted abandoned splays of the Proto-Rosedale Fault forming the Tuna faulted anticline oil and gas traps.The Santonian-Campanian Proto-Rosedale Fault and other similarly oriented structures are promising fairways for deep exploration. Attractive reservoir targets include stacked braided fluvial channel sands of the Golden Beach Subgroup deposited along NE–SW to ENE–WSW trending segments of the Proto-Rosedale Fault. Anticlinal traps developed during multiple Cretaceous and Tertiary compressive phases. Campanian dykes, sills and flows are prevalent in the Golden Beach section and offer the potential for effective seal as seen in the Kipper field.
FLATTENED TIME SLICES—A STRATIGRAPHIC APPROACH TO 3D SEISMIC INTERPRETATION ON THE NORTH WEST SHELF OF AUSTRALIA
Authors: Martens K.
Published: August 2017

Conventional time slices are a powerful method of integrating horizon picks and fault picks into a unified interpretation and are a handy way of viewing structures, especially in faulted areas. The limitation is that time slices are seldom useful in viewing the morphology of a horizon. A 3D cube is the present day structural volume; it retains any structure imparted on the geology after deposition. When a time slice is defined, the structural dip limits the area of the integral depositional elements that can be imaged. For example, a depositional surface developed as part of a fluvial-deltaic system is seldom one event and it cannot be easily identified and picked in a vertical section. Flattened time slices take out the regional dip and allow a complete depositional surface to be viewed.The North West Shelf of Australia and especially the Barrow Sub-basin is a particularly suitable place to apply this exploration technique. The entire sedimentary package, laid down in a variety of depositional environments, has been tilted to the northwest by an average of 3°. This strong post-depositional tilt limits the uses of conventional time slices to imaging only the diprelated features of an area. Whereas conventional time slices only make apparent the dip of the section, flattened time slices can reveal subtle and intricate stratigraphic architecture.This paper describes the seismic features of a number of depositional systems from the Barrow Sub-basin and outlines how complex channel systems can be determined by the use of the flattened time slice approach. Given the importance of stratigraphic plays in the Barrow Subbasin, the technique outlined in this paper is considered to be an important exploration tool.
SUB-SURFACE UNCERTAINTY IN OIL FIELDS: LEARNINGS FROM EARLY PRODUCTION OF LEGENDRE OIL FIELDS
Authors: Seggie R. , Jamal F. , Jones A. , Lennane M. , McFadzean G. , Rogers J.
Published: August 2017

The Legendre North and South Oil Fields (together referred to as the field) have been producing since May 2001 from high rate horizontal wells and had produced 18 MMBBL by end 2002. This represents about 45% of the proven and probable reserves for the field.Many pre-drill uncertainties remain. The exploration and development wells are located primarily along the crest of the structure, leaving significant gross rock volume uncertainty on the flanks of the field. Qualitative use of amplitudes provides some insight into the Legendre North Field but not the Legendre South Field where the imaging is poor. The development wells were drilled horizontally and did not intersect any fluid contacts.Early field life has brought some surprises, despite a rigorous assessment of uncertainty during the field development planning process. Higher than expected gas-oil ratios suggested a saturated oil with small primary gas caps, rather than the predicted under-saturated oil. Due to the larger than expected gas volumes, the gas reinjection system proved to have inadequate redundancy resulting in constrained production from the field. The pre-drill geological model has required significant changes to reflect the drilling and production results to date. The intra-field shales needed to be areally much smaller than predicted to explain well intersections and production performance. This is consistent with outcrop analogues.Surprises are common when an oil field is first developed and often continue to arise during secondary development phases. Learnings, in the context of subsurface uncertainty, from other oil fields in the greater North West Shelf are compared briefly to highlight the importance of managing uncertainty during field development planning. It is important to have design flexibility to enable facility adjustments to be made easily, early in field life.
PETROLEUM SYSTEMS AND EXPLORATION POTENTIAL IN THE OFFICER BASIN, WESTERN AUSTRALIA
Authors: Carlsen G.M. , Simeonova A.P. , Apak S.N.
Published: August 2017

The Officer Basin in Western Australia contains a variety of hydrocarbon plays associated with compressional, halokinetic, unconformity and stratigraphic traps. Five distinct structural zones have been defined in the basin—a northeastern Marginal Overthrusted Zone, a northeastern Salt-ruptured Zone, a central Thrusted Zone, a Western Platform and a complex salt-dominated Minibasins Zone. These zones, together with salt-associated and sub-salt structure, are well delineated on about 2,900 km of reprocessed 1980s vintage seismic data, now publicly released.Neoproterozoic rocks are marginally to fully mature for oil generation on the Western Platform and immature to overmature for different levels of the succession in the Salt-ruptured and Thrusted zones. Geochemical modelling indicates that the main phases of oil generation vary from different stratigraphic intervals and different parts of the Neoproterozoic basin with peaks during the latest Neoproterozoic, Cambrian, and Permian–Triassic. A variety of hydrocarbon shows have been recorded in each of the structural zones. The most recent, a gas show recorded in the stratigraphic well Vines–1 indicates the presence of potentially effective petroleum systems in the unexplored Waigen area of the Marginal Overthrusted Zone.A wide variety of trap styles have been identified, associated with normal faults, thrust faults, thrust ramp folds, compressive folds, fault tip folds, sub-salt plays, unconformity truncations, pinchouts, lateral facies changes, erosive channels and valleys, fractured carbonates and halokinetic traps. Most of these trap styles are poorly tested or untested.
AN INTEGRATED GEOLOGICAL AND GEOPHYSICAL INTERPRETATION OF A PORTION OF THE OFFSHORE SYDNEY BASIN, NEW SOUTH WALES
Authors: Arditto P.A.
Published: August 2017

The study area is within PEP 11, which is more than 200 km in length, covers an area over 8,200 km2 and lies immediately offshore of Sydney, Australia’s largest gas and petroleum market on the east coast of New South Wales. Permit water depths range from 40 m to 200 m. While the onshore Sydney Basin has received episodic interest in petroleum exploration drilling, no deep exploration wells have been drilled offshore.A reappraisal of available data indicates the presence of suitable oil- and wet gas-prone source rocks of the Late Permian coal measure succession and gas-prone source rocks of the middle to early Permian marine outer shelf mudstone successions within PEP 11. Reservoir quality is an issue within the onshore Permian succession and, while adequate reservoir quality exists in the lower Triassic succession, this interval is inferred to be absent over much of PEP 11. Quartz-rich arenites of the Late Permian basal Sydney Subgroup are inferred to be present in the western part of PEP 11 and these may form suitable reservoirs. Seismic mapping indicates the presence of suitable structures for hydrocarbon accumulation within the Permian succession of PEP 11, but evidence points to significant structuring post-dating peak hydrocarbon generation. Uplift and erosion of the order of 4 km (based on onshore vitrinite reflectance studies and offshore seismic truncation geometries) is inferred to have taken place over the NE portion of the study area within PEP 11. Published burial history modelling indicates hydrocarbon generation from the Late Permian coal measures commenced by or before the mid-Triassic and terminated during a mid-Cretaceous compressional uplift prior to the opening of the Tasman Sea.Structural plays identified in the western and southwestern portion of PEP 11 are well positioned to contain Late Permian clean, quartz-rich, fluvial to nearshore marine reservoir facies of the coal measures. These were sourced from the western Tasman Fold Belt. The reservoir facies are also well positioned to receive hydrocarbons expelled from adjacent coal and carbonaceous mudstone source rock facies, but must rely on early trap integrity or re-migrated hydrocarbons and, being relatively shallow, have a risk of biodegradation. Structural closures along the main offshore uplift appear to have been stripped of the Late Permian coal measure succession and must rely on mid-Permian to Early Permian petroleum systems for hydrocarbon generation and accumulation.
A PONDED BASIN FLOOR FAN OUTCROP ANALOGUE: BUNKERS SANDSTONE, NORTHERN FLINDERS RANGES, AUSTRALIA
Authors: Reilly M.R.W. , Lang S.C.
Published: August 2017

The Donkey Bore Syncline in the Northern Flinders Ranges of South Australia contains a generally finegrained deepwater succession of Early Cambrian age (Bunkers Sandstone) that outcrops on three sides of a syncline and flanks an active salt diapir to the east (Wirrealpa Diapir). Within the succession lies a basal sand-prone interval interpreted as a basin floor fan (BFF) ponded within a mini-basin on a topographically complex slope.The BFF comprises over 30 m of section with deposits that are dominantly massive clean sandstone beds (0.1– 3 m thick) that are stacked or interbedded with siltstones and pinch out along strike.Eight stratigraphic sections and accompanying spectral gamma ray logs (using a hand held scintillometer) were measured through the BFF. Using spectral gamma ray log analysis combined with stratigraphic logs, four alternative correlation panels were constructed.Quantitative analysis of sand-prone intervals interpreted in each of the panels provided data on the vertical and horizontal connectivity within the BFF as different correlation methods were explored and the geological model improved. Quantitative analysis of vertical and horizontal connectivity values indicates a high degree of heterogeneity within the BFF, with poor–moderate vertical connectivity, with individual beds rarely correlating >500 m along strike. This heterogeneity is poorly resolved using conventional wireline log suites, but is greatly improved if spectral gamma ray logs are used (especially Thorium).The data set provides a high-resolution analogue for understanding the internal architecture of deepwater hydrocarbon reservoirs.
APPLICATIONS OF SPECTROLITH MINERALOGY FROM NEUTRON CAPTURE SPECTROSCOPY TOOLS FOR FORMATION EVALUATION
Authors: Pallikathekathil Z.J. , Wilson M.
Published: August 2017

When performing a petrophysical analysis, an accurate understanding of the mineralogy of the formations of interest is important for two main reasons. Firstly, the mineralogy of the formations controls the matrix density, which is fundamental in the evaluation of porosity using conventional methods. Secondly, an accurate estimate of the fraction of clay minerals present in the formation is essential in accurately correcting resistivity-based saturation estimates for the effects of excess clay conductivity.Accurately evaluating the mineralogy in formations containing both gas and radioactive minerals such as feldspars can be a challenge. Traditional clay indicators such as gamma ray estimate clay volumes which are too high due to the radioactivity coming from matrix grains such as potassium feldspars, feldspar rich volcanolithic grains and muscovite. In formations having light hydrocarbon such as gas or condensate, density-neutron logs under-estimate the volume of clays due to the light hydrocarbon effects on the density and neutron logs. Moreover, if the logs are to be acquired in a borehole with gas, air or foam, only a limited number of tools sensitive to mineralogy may be run. Using the SpectroLith technique, data from neutron capture spectroscopy tools such as the Reservoir Saturation Tool (RST) or Elemental Capture Spectroscopy Sonde (ECS) can be used to provide answers in these challenging situations.The RST is normally logged in cased hole for the sigma or carbon/oxygen ratio logs useful for determining formation saturation. The SpectroLith processing extracts lithology information, and in turn the weight proportion of clay, quartz-feldspar-mica, carbonate, pyrite, anhydrite and coal. The ECS tool is optimised for providing SpectroLith results at faster logging speeds in larger boreholes.This paper demonstrates, through examples from Australia, the applications of SpectroLith results derived from RST and ECS measurements. Two examples with the RST and one with the ECS are presented. In one example, the only available source of mineralogical information was from the results of SpectroLith processing applied to RST data. The second example shows how SpectroLith results can complement a through casing petrophysical evaluation. The example using ECS compares the mineralogy from a traditional analysis with that from SpectroLith processing and demonstrates the improvements to the petrophysical evaluation through a more accurate mineralogical description. Although no complete examples are available in gas wells in Australia at present, SpectroLith provides a promising way for accurately estimating mineralogy in gas wells.
WARD AND WILSON V ANDERSON—EVOLUTION OR REVOLUTION IN NATIVE TITLE LAW?
Authors: Young D. , Scott G.
Published: August 2017

There is now a greater degree of certainty for the petroleum industry in Native Title law following the High Court’s decisions in Ward v Western Australia1 and Wilson v Anderson2. Both decisions were handed down on 8 August 2002. Ward in particular is the most significant Native Title decision in Australia since the High Court’s decision in Wik v Queensland3 in 1996. This paper presents an analysis of the issues dealt with in Ward and Wilson v Anderson with particular emphasis on the application for petroleum. The paper will also illustrate that while greater certainty flows from these decisions, it is still necessary for petroleum and resource companies to engage with Native Title groups (particularly by negotiating agreements) to enable the valid grant of titles and tenements to land subject to Native Title.
ENVIRONMENTAL MANAGEMENT IN THE BASS STRAIT NORTHERN FIELDS 3D SEISMIC SURVEY
Authors: Mustoe S.H. , Greenwood M.C. , Moore J.F.
Published: August 2017

The Northern Fields 3D seismic survey in Bass Strait was a large survey of 4,000 km2, carried out between the months of October 2001 to July 2002. The program attracted interest from various groups regarding the possible impacts of the survey on fisheries and cetaceans (whales and dolphins).The survey was the first to operate in eastern Bass Strait after the Environment Australia Guidelines for Minimising Acoustic Disturbance to Whales, came into force, in September 2001.The Northern Fields program was conducted in accordance with a method statement for the mitigation of impacts to cetaceans, developed by Esso to meet the requirements of Australian environmental legislation and acknowledge environmental best practice. The program utilised teams of three whale watchers who maintained a continuous rotational watch of two observers throughout the day. This proved to be a reliable element of the program and was one of several key learnings that may assist other companies in developing comprehensive and cost-effective mitigation strategies for future surveys.Concerns raised by the fishing industry and some conservation groups about the potentially detrimental impact of seismic sources on commercial scallop larvae and fish populations were effectively addressed by avoiding commercial scallop areas during spawning periods. A controlled, in-situ study of scallops exposed to the acoustic source completed during the program conclusively demonstrated no significant variation in scallop mortality or muscle strength.Observation data collected during this survey provided a sample of the cetacean population in Eastern Bass Strait during a large part of the annual migration cycle. These observations, which may be relevant to the planning and execution of future seismic surveys in the region, are discussed. The findings also provide valuable information for continued research into the distribution and conservation of whales and dolphins in Bass Strait.
HAZ & ZARD: PROMOTING HAZARD IDENTIFICATION, RISK ASSESSMENT AND POSITIVE SAFETY BEHAVIOUR IN THE PETROLEUM INDUSTRY
Authors: Marshall G.C.
Published: August 2017

The Australian Petroleum Production and Exploration Association (APPEA) represents companies exploring for, and producing, oil and gas in Australia. APPEA has a responsibility to the community and an obligation to its membership to improve the health, safety, and environmental (HSE) awareness of new recruits entering the energy sector from schools and to reinforce awareness and safe behaviour amongst experienced personnel. Unfortunately, however, APPEA noted that school-based HSE training was virtually non-existent and much preexisting lecture-based HSE training was inconsequential because the traditional death by PowerPoint approach did not enable people to think for themselves. In essence, much safety training has failed to capture the hearts and minds of employees. In response, APPEA, with the financial support of ChevronTexaco Australia Pty Ltd and the professional and technical support of An Meá, developed a hazard identification and risk awareness training activity that promotes safety from the heart by actively engaging the minds of students and employees.The Haz & Zard Safety Awareness Activity is not a lecture or talking-head experience. Haz & Zard is an active process of adult learning that forces trainees and students to think. At a psychological level, Haz & Zard uses a projective technique with computer-generated HSE images across a range of workplace activities. The projective training process enables participants to identify and assess hazards and associated risks, and then define hundreds of appropriate safe behaviours and practices in response. Intra-group discussions further heighten learning and a participant workbook enables the capture and evaluation of training outcomes. To reiterate the main point, there is no place within Haz & Zard for an HSE lecture. Instead, Haz & Zard enables active participation and advanced discussion of a wide range of HSE issues to enhance learning outcomes and motivate positive safety behaviour.
EFFECTIVE SAFETY CASE DEVELOPMENT
Authors: Mathers A.J. , Savva S.
Published: August 2017

Esso Australia Pty Ltd, in Victoria, Australia has recently been involved in the preparation of over 20 safety cases to meet both offshore (Victoria and Western Australia) [Petroleum {Submerged Lands} Act] and onshore [Victorian Occupational Health and Safety Act] regulatory requirements.This paper focusses on the development of the onshore safety cases for both Longford and Long Island Point plants to meet the Victorian Occupational Health and Safety (Major Hazard Facilities) Regulations 2000. Both plants have been granted a five-year unconditional licence to operate.The objectives of the safety case development were to ensure that Esso:addressed major hazard facilities regulatory requirements; maximised benefit from the process, and to maximise benefit from existing work; was consistent with site approach to risk assessment/ safety culture; involved appropriate workforce from all areas— operations, maintenance and technical support; enhanced the effective knowledge and understanding of the workforce; and developed a communication tool to enable ease of understanding by site personnel.Esso’s approach of using qualitative risk assessment techniques (familiar to many site personnel) enabled the process to use tools that provided ease of involvement for the non-technical or safety specialists. This paper will explain this approach in greater detail, demonstrating how this successfully met the stringent requirements of the regulations whilst providing Hazard Register documentation readily understood by the key customer— our site workforce.The hazard register clearly identifies the relevant hazards and their controls, as well as highlighting the linkages to the safety management system and documented performance standards. A comprehensive training program provides all personnel working at site with an overview of the safety case, and the necessary skills and knowledge to be able to use the safety case and hazard register to its maximum advantage. The safety case resource booklet (similar to our offshore approach) is an integral part of the training program, and provides an ongoing reference source for trainees. It continues to receive recognition by both regulators and industry.
PRODUCTION AND DEVELOPMENT HIGHLIGHTS IN 2002
Authors: Slatford Madeleine
Published: August 2017

An encouraging number of development projects were pursued during 2002. Progress was made with major ongoing projects such as Bayu-Undan and smaller niche projects such as Patricia-Baleen. Redevelopment projects such as Buffalo, and, on paper, major steps forward were made with advancing new field developments, including the possible implementation of FLNG at Greater Sunrise. These and other ongoing development projects are reviewed.
JURASSIC PETROLEUM SYSTEMS IN THE HOUTMAN SUB-BASIN, NORTHWESTERN OFFSHORE PERTH BASIN, WESTERN AUSTRALIA: A FRONTIER PETROLEUM PROVINCE ON THE DOORSTEP?
Authors: Gorter J.D. , Hearty D.J. , Bond A.J.
Published: August 2017

The under-explored Houtman Sub-basin, a northwestern offshore extension of the hydrocarbon-productive Perth Basin of southwestern Australia, formed during Jurassic rifting of Gondwana. The sub-basin contains the ingredients for an exciting frontier petroleum province with typical rift architecture. Permian, Triassic and Jurassic petroleum systems are proven from the onshore region, with a productive Triassic-sourced hydrocarbon system recently demonstrated in the adjacent Abrolhos Sub-basin by the Cliff Head oil discovery, and several basal Triassic-sourced oil shows. Gas and oil shows from the Early to Middle Jurassic Cattamarra Coal Measures in Houtman–1, the only well drilled in the 32,000 km2 Houtman Sub-basin, are most likely sourced from the organic-rich Cattamarra Coal Measures and are sealed by intraformational shales and the overlying regional marine shale of the Cadda Formation. The disappointing result of Houtman–1 has coloured perceptions of the prospectivity of the Houtman Sub-basin. Despite this negativity, recent seismic acquisition and reprocessing have demonstrated the presence of large structural closures in the sub-basin that could contain substantial oil reserves as indicated by geochemical modelling of the Cattamarra Coal Measures source rocks. Analyses on GOI indicate a palaeo-oil zone at the top of the Cattamarra Coal Measures in Houtman–1 indicating that the gas-prone perception may not be true. QGF intensities from Houtman–1 suggest oil migration in sandstones beneath intra-formational seals in both the Late Jurassic Yarragadee Formation and the Cattamarra Coal Measures. In addition to reservoir sandstones, source rock intervals occur in the lower Yarragadee Formation, but regional sealing units in this formation are to be confirmed.
USING 2D AND 3D BASIN MODELLING TO INVESTIGATE CONTROLS ON HYDROCARBON MIGRATION AND ACCUMULATION IN THE VULCAN SUB-BASIN, TIMOR SEA, NORTHWESTERN AUSTRALIA
Authors: Fujii T. , O’Brien G.W. , Tingate P. , Chen G.
Published: August 2017

2D and 3D basin models have been constructed of the southern and central parts of the Vulcan Sub-basin region, in the Timor Sea. This work was carried out to better elucidate the petroleum migration and accumulation histories, and exploration potential, of the region.2D/3D modelling in the Swan Graben indicates that horizontal and downward oil expulsion from the source rocks of the Late Jurassic Lower Vulcan Formation into the Plover Formation sandstone was active from the Early Cretaceous to the present day. Oil migration from the Lower Vulcan Formation into the Late Cretaceous Puffin Formation sands in the Puffin field was simulated by lateral migration along the bottom of an Upper Vulcan Formation seal and by vertical migration above the seal edge. Modelling also indicates that Late Jurassic sequences over the Montara Terrace are thermally immature, and did not contribute to the hydrocarbon accumulations in the region. On the other hand, 3D modelling results indicate that Middle Jurassic Plover Formation in the Montara Terrace became thermally mature after the Pliocene and hence it could contribute both to the hydrocarbon accumulations and the overall hydrocarbon inventory in the area.In the southern Cartier Trough, the Lower Vulcan Formation is typically at a lower thermal maturity than that seen in the Swan Graben, due to a combination of a relatively recent (Pliocene) enhanced burial history and a thinner Lower Vulcan Formation. Here, horizontal and downward oil/gas expulsion from the Lower Vulcan Formation into the Plover Formation sandstone was active from the Late Tertiary to present day, which is significantly later than the expulsion in the Swan Graben. Oil migration from the Lower Vulcan Formation into the Jabiru structure via the Plover Formation carrier bed, was simulated in both 2D and 3D modelling. In particular, 3D modelling simulated oil migration into the Jabiru structure, not only from the southern Cartier Trough after the Miocene, but also early migration from the northern Swan Graben in the Early Cretaceous.In the central Cartier Trough, the areal extent of both generation and expulsion increased as a result of rapid subsidence from about 5 Ma to present day. This Pliocene loading has resulted in the rapid maturation of the Early to Middle and Late Jurassic source system, and expulsion of oil very recently.
THE NORTHERN PERTH BASIN—FROM MARGINALLY PROSPECTIVE FOR GAS TO HIGHLY PROSPECTIVE FOR BOTH OIL AND GAS
Authors: Buswell A.J. , Powell W.D. , Scholefield T.
Published: August 2017

Recent discoveries of gas in the Wagina Formation by Beharra Springs North–1, in the High Cliff Sandstone by Hovea–2, and of oil in the Dongara Sandstone by Hovea–1, Jingemia–1 and Eremia–1, have changed the perception of the northern Perth Basin from being marginally prospective for gas to one that is highly prospective for both oil and gas. Enhanced quality of 3D seismic over 2D, an analysis of regional gravity data, and in-house reservoir and source rock studies have all played a part in these discoveries. Hovea–2 is significant in that it flowed gas at commercial rates from the Lower Permian High Cliff Sandstone, the first well in the basin to do so from this reservoir. A program involving extensive additional 3D seismic and as many as six exploration wells is planned for 2004, offering the potential for further significant hydrocarbon discoveries.
GEOCHEMICAL AND COMPOUND SPECIFIC CARBON ISOTOPIC CHARACTERISATION OF FLUID INCLUSION OILS FROM THE OFFSHORE PERTH BASIN,WESTERN AUSTRALIA: IMPLICATIONS FOR RECOGNISING EFFECTIVE OIL SOURCE ROCKS
Authors: Volk H. , George S.C. , Boreham C.J. , Kempton R.H.
Published: August 2017

The molecular composition of fluid inclusion (FI) oils from Leander Reef–1, Houtman–1 and Gage Roads–2 provide evidence of the origin of palaeo-oil accumulations in the offshore Perth Basin. These data are complemented by compound specific isotope (CSI) profiles of n-alkanes for the Leander Reef–1 and Houtman–1 samples, which were acquired on purified n-alkane fractions gained by micro-fractionation of lean FI oil samples, showing the technical feasibility of this technique. The Leander Reef–1 FI oil from the top Carynginia Formation shares many biomarker similarities with oils from the Dongara and Yardarino oilfields, which have been correlated with the Early Triassic Kockatea Shale. The heavier isotopic values for the C15-C25 n-alkanes in the Leander Reef–1 FI oil indicate, however, that it is a mixture, and suggest that the main part of this oil (~90%) was sourced from the more terrestrial and isotopically heavier Early Permian Carynginia Formation or Irwin River Coal Measures. This insight would have been precluded when looking at molecular evidence alone. The Houtman–1 FI oil from the top Cattamarra Coal Measures (Middle Jurassic) was sourced from a clay-rich, low sulphur source rock with a significant input of terrestrial organic matter, deposited under oxic to sub-oxic conditions. Biomarkers suggest sourcing from a more prokaryotic-dominated facies than for the other FI oils, possibly a saline lagoon. The Houtman–1 FI oil δ13C CSI n-alkane data are similar to those acquired on the Walyering–2 oil. Possible lacustrine sources may exist in the Early Jurassic Eneabba Formation and are present in the Late Jurassic Yarragadee Formation. The low maturity Gage Roads–2 FI oil from the Carnac Formation (Early Cretaceous) was derived from a strongly terrestrial, non-marine source rock containing a high proportion of Araucariacean-type conifer organic matter. It has some geochemical differences to the presently reservoired oil in Gage Roads–1, and was probably sourced from the Early Cretaceous Parmelia Formation.
THE EVOLUTION OF THE BERNIER RIDGE, SOUTHERN CARNARVON BASIN, WESTERN AUSTRALIA:IMPLICATIONS FOR PETROLEUM PROSPECTIVITY
Authors: Lockwood A.M. , D’Ercole C.
Published: August 2017

The basement topography of the Gascoyne Platform and adjoining areas in the Southern Carnarvon Basin was investigated using satellite gravity and seismic data, assisted by a depth to crystalline basement map derived from modelling the isostatic residual gravity anomaly. The resulting enhanced view of the basement topography reveals that the Gascoyne Platform extends further westward than previously indicated, and is bounded by a northerly trending ridge of shallow basement, named the Bernier Ridge.The Bernier Ridge is a product of rift-flank uplift prior to the Valanginian breakup of Gondwana, and lies east of a series of small Mesozoic syn-rift sedimentary basins. Extensive magmatic underplating of the continental margin associated with this event, and a large igneous province is inferred west of the ridge from potential field and seismic data. Significant tectonic events that contributed to the present form of the Bernier Ridge include the creation of the basement material during the Proterozoic assembly of Rodinia, large-scale faulting during the ?Cambrian, uplift and associated glaciation during the early Carboniferous, and rifting of Gondwana during the Late Jurassic. The depositional history and maturity of the Gascoyne Platform and Bernier Ridge show that these terrains have been structurally elevated since the mid-Carboniferous.No wells have been drilled on the Bernier Ridge. The main source rocks within the sedimentary basins west of the Bernier Ridge are probably Jurassic, similar to those in the better-known Abrolhos–Houtman and Exmouth Sub-basins, where they are mostly early mature to mature and within the oil window respectively. Within the Bernier Ridge area, prospective plays for petroleum exploration in the Jurassic succession include truncation at the breakup unconformity sealed by post-breakup shale, and tilted fault blocks sealed by intraformational shale. Plays in the post-breakup succession include stratigraphic traps and minor rollover structures.
POST–EARLY CARBONIFEROUS THERMAL HISTORY RECONSTRUCTION FROM WELL DATA IN THE AMADEUS BASIN, CENTRAL AUSTRALIA
Authors: Gibson H.J. , Ambrose G. , Duddy I.R. , Tingate P.R. , Marshall T.
Published: August 2017

Apatite Fission Track Analysis (AFTA) combined with maturity data has revealed that four (possibly five) cooling events affected the northern margin of the Amadeus Basin since the Early Carboniferous. A consistent regional thermal history framework is developed, with recognition of cooling events beginning in the Carboniferous/Early Permian (between ~360 and 290 Ma), the Early Jurassic (~200 Ma), Late Cretaceous (between ~80 and 70 Ma) and Tertiary (between ~ 25 and 20 Ma). We suggest the first of these reflects uplift and erosion associated with the Alice Springs Orogeny, while Early Jurassic cooling reflects uplift and erosion associated with the Fitzroy Movement. Uplift and erosion in the Late Cretaceous probably relates to the breakup of Australia and Antarctica (opening of the Tasman Sea) at about this time. Later uplift and erosion in the Miocene may reflect Neogene collision of the Australian and SE Asian Plates in the region of the Banda Arc.In Tyler–1 (northern Amadeus Basin), maturation modelling using paleotemperature constraints from AFTA and VR equivalent data suggests the main source rock horizon (Ordovician Horn Valley Siltstone), went through the dry gas window during burial associated with the latter stages of the Alice Springs Orogeny. Basinward (south) of this foreland wedge, the influence of Devonian-Carboniferous loading decreases enabling oil expulsion from the Horn Valley Siltstone to have charged the Mereenie Structure. This was later partially displaced by gas.To date the Neoproterozoic sequences have yielded only dry gas (at Dingo field, Ooraminna–1 and Magee–1) which could be due to original source rock characteristics, but more likely to high maturity levels in the main depocentres. Previous notions that the Ordovician petroleum system was probably only active in the northern portion of the basin appear correct, but gas charged traps at the level of the Neoproterozoic should be ubiquitous.
OPTIMAL THIN OIL COLUMN MANAGEMENT—THE BREAM STORY
Authors: Fish R.M. , Zajdlewicz D.J.
Published: August 2017

Originally developed in 1987 for oil, the Bream N-1 reservoir is a Gippsland Basin Top-of-Latrobe oil and gas accumulation. The original oil column thickness varied due to local structure with most of it 13.5 m and with nearly all of it overlain by a large gas cap. The original depletion plan called for maximising oil recovery through a combination drive and included a provision for returning all produced gas to the reservoir. By 2000 this scheme had proven successful with a 60% oil recovery. The remaining life of the oil resource was, however, limited and a study of the optimum time to initiate gas withdrawals was undertaken.Gas blow-down studies often employ full-field reservoir simulations. This stratigraphically complex reservoir is not suited to full-field modelling due to the interplay of a coning dominated thin oil column with a thinly bedded dipping reservoir. Consequently a different, more efficient tack was taken.key unswept oil areas were identified and studied for their response to a moving oil column, either through mechanistic simulations or analytically. This study with subsequent revisions concluded that gas export would increase Bream’s oil recovery by as much as 9.6 MMSTB (1.5 GL) through an active campaign of chasing the moving oil column and/or accessing it at local structural traps.Gas export started in December 2002 after the construction of a new pipeline. Wellbore preparations were initiated in 2001 with the re-activation of previously depleted wells and the re-completion upward of existing wells. These activities have proven successful with Bream cumulative oil recovery now at 66% and oil rates higher than they have been since 1999.
ADVANCES IN VISUALISATION TECHNOLOGIES: A CASE STUDY, LAHO GAS FIELD—OFFSHORE PENINSULAR MALAYSIA
Authors: Gell C.M. , Meyer D.E. , Majid R.A. , Carr D.J.
Published: August 2017

A typical problem facing oil company asset teams today is the integration of new information into existing fields. Recently acquired 3D seismic for example, can add much needed detail for understanding reservoirs from producing wells. The key step of interpreting faults and surfaces, on which many other results depend, can often be time consuming and delay efforts to bring additional oil and gas production on-line. Using a volume-based approach to seismic interpretation with today’s visualisation technology, however, can lead to more accurate results produced up to four times faster than traditional line-by-line methods.Over the last four years, visualisation technologies have advanced to the point where these new techniques provide a faster, more geologically correct interpretation and evaluation of potential reservoirs in a shorter amount of time by comparison with line-by-line methods. These advanced techniques include, but are not limited to: multiple attribute voxel interpretation; interpreting fault planes (rather than fault sticks); real-time volume rendering with the ability to create geobodies; quick reconnaissance work in volume; the ability to combine workflows using non-3D volume tools such as wave-form classification with volume interpretation.This paper provides an example of the Laho gas field, offshore Peninsular Malaysia, where two wells were already producing gas and the operator, Petronas Carigali Sdn. Bhd (PCSB), acquired 3D data to evaluate the possibility of additional drilling locations.
THE CHINGUETTI DEEPWATER TURBIDITE FIELD, MAURITANIA: RESERVE ESTIMATION AND FIELD DEVELOPMENT USING UNCERTAINTY MANAGEMENT AND EXPERIMENTAL DESIGNS FOR MULTIPLE SCENARIO 3D MODELS
Authors: Smith G.C. , Rayfield M.A. , DePledge D.R. , Gupta R.
Published: August 2017

The Chinguetti Field was discovered in 2001 offshore Mauritania in 800 m of water. It comprises deepwater, mid-slope turbidite reservoirs, trapped in a dome over a salt diapir. The hydrocarbons are compartmentalised by concentric radial faults, in a low net:gross sequence, with oil mainly in channel sands. The large number of uncertain variables requires a structured approach and a rigorous assessment of the potential sub-surface scenarios. The field is of moderate size and risks in this deepwater environment need to be managed carefully.The main sub-surface uncertainties were identified by uncertainty framing and are briefly described in the paper. They include:structure;hydrocarbon contacts;fault seal;distribution of the channel systems;frequency and amalgamation of channel sands;shale drape;internal channel heterogeneity;effective pressure support;rock-fluid interaction;rock compaction;fluid composition/properties; androck properties.A statistical experimental design determined 27 scenarios should accurately model the probability distribution of reserves. A 3D model was made for each and run through the dynamic simulator to estimate economic ultimate recovery (EUR). Multivariate statistical analysis produced a response equation for EUR and the probability distribution. This is more rigorous than the standard method which produces mid, high and low case models, for which there is no adequate way to assign their probability of occurrence.
DRIVERS FOR THE DEVELOPMENT OF AN INTEGRATED SUPPLY BASE AND OFFSHORE SUPPLY CHAIN, NORTH WEST SHELF, AUSTRALIA
Authors: Graham E.D.
Published: August 2017

Since the commencement of the major developments on the North West Shelf, the offshore resource industry, during both its construction and operational phases, has faced considerable logistical impediments to cost-effective solutions for the offshore supply chain. These impediments have included distance, scant resources, lack of infrastructure both on and offshore and lack of critical mass.Throughout the world, offshore projects have greatly benefitted from the availability of integrated services to cater for the transport of equipment from the point of manufacture or distribution to the offshore location.Within the Australian context the privately controlled Esso Barry Beach and Dampier Woodside facilities are examples of integrated services, but both differ considerably from a public multi-user facility. The model used in the Timor Sea of one vessel or vessels for the use of several operators is another example.The NorthWest Shelf has now reached the critical mass and it became apparent several years ago that the area needed an integrated supply base available to multiple operators. It would need to include a heavy loadout wharf, laydown areas, slipway and engineering facilities and office space to service forthcoming projects, as well as planning and cooperation amongst all players to maximise efficiency and use of scant resources as drivers for economic benefits to offshore operators in the region.Furthermore the fallout from the events of 11 September 2001 and continuing threats of terrorism has meant the security of marine assets has become an important part of each operator’s everyday life. The introduction of new legislation relating to this security issue is planned for mid 2004.In 2000 and 2001 Mermaid Marine Australia Limited undertook a major expansion of its Dampier supply base, and established a world-class facility to meet the growing demands of the region.This complex has for the first time provided the northwest of Australia, particularly the North West Shelf, Carnarvon Basin and the onshore developments on the Burrup Peninsula, with a facility for offloading and loadout of heavy shipments and fabrication and slipway facilities, coupled with the advantages of a large supply base. This facility can also be expanded to meet growth and the emerging requirements related to security.This paper describes the drivers for change commencing with the earliest supply chains and following through to the integrated service now availabe. These drivers meet the requirements of the offshore operators in the region as well as showing the benefits anticipated from this integrated service. The paper also outlines in detail the requirements of the International Maritime Organisation for worldwide changes to port and offshore security.
REAL-TIME AND ON-SITE RESERVOIR FLUID CHARACTERISATION USING SPECTRAL ANALYSIS AND PVT EXPRESS
Authors: Jamaluddin A.K.M. , Dong C. , Hermans P. , Khan I.A. , Carnegie A. , Mullins O.C. , Kurkjian A. , Fujisawa G. , Nighswander J. , Babajan S.
Published: August 2017

Obtaining an adequate fluid characterisation early in the life of a reservoir is becoming a key requirement for successful hydrocarbon development. This work presents and discusses a number of new fluid sampling and fluid characterisation technologies that can be deployed either down hole or at surface in the early stages of the exploration and development cycle to achieve this objective. Techniques discussed include methods to monitor and quantify oil-based mud contamination, gas-liquid-ratio (GLR) and basic fluid composition in real time during open-hole formation testing operations. In addition, we demonstrate the applicability of new surface analysis techniques that allow for rapid, accurate, and reliable measurements of key fluid properties, such as saturation pressure, gas-oil ratio, extended carbon number composition, viscosity, and density, on-site within a few hours of retrieving reservoir fluid samples at surface. Finally, prediction tools used to extend these limited measurements to a traditional PVT fluid characterisation are presented along with example measurements from all the techniques described. In conclusion, it is shown that the implementation of these techniques in a complementary program can reduce the risk associated with making key development decisions that are based on an understanding of reservoir fluid properties.
ASPHALTENE CHARACTERISATION USING SPECTRAL ANALYSIS SYSTEM
Authors: Jamaluddin A.K.M. , Nighswander J. , Joshi N. , Mullins O.C. , Forde C. , Barraclough P.
Published: August 2017

Asphaltenes are the heaviest hydrocarbon component of crude oil and remain in colloidal suspension under reservoir temperature and pressure conditions. These materials may flocculate and deposit as a result of pressure, temperature and compositional changes, and consequently, disrupt production operations. This disruption can have severe implications, particularly in an offshore subsea environment. In these circumstances, it is imperative to understand the fundamental behaviour of asphaltenes prior to the development phase of any field under consideration.In this paper, we present a novel methodology to understand the thermodynamic asphaltene instability conditions using near infrared and spectral analysis system (SAS) techniques. Using the SAS technique, we were able to estimate the asphaltene particle size and growth behaviour as functions of pressure and time. Asphaltene particle size determined at the onset of asphaltene flocculation is in the order of 0.25 μm for a pressure-compensated sample. On the other hand, the asphaltene particle size is determined to be about 0.8 μm at the onset pressure using a conventional sample. Results also indicate that the particles from the pressure-compensated sample had a slower initial growth rate compared to the particles growth rate estimated from the non-pressure compensated sample. These results demonstrate the importance of representative sampling on asphaltene characterisation.