bluuebunny/crossref_metadata_2025 huggingface dataset:
IMPROVING FIELD PRODUCTION AND THE VALUE OF ASSETS THROUGH ENABLING REAL-TIME WORKFLOWS
Authors: Theuveny B. , Amedick J. , Kosmala A. , Flores J.G. , Soliman H.
Published: August 2017

Reservoir and production management practices can benefit from the use of information obtained in real-time. This paper focusses specifically on the gains obtained from the continuous monitoring of naturally flowing and artificially lifted wells.The deployment of real-time production workflows is an important enabler to improve the value of oil and gas assets. The impact is seen in areas such as:the improvement of production (well productivity), through the reduction of deferred production and increased productivity;reduction of operating costs (OPEX);reduction of repair time;reduction of capital expenses (CAPEX);capture of best (and worst) practices;increased operational flexibility; andimproved efficiency of workforce.Field examples over a range of applications covering both artificially lifted wells to naturally flowing wells demonstrate the value of real-time monitoring and relevant-time surveillance and diagnostic applications. Examples of permanent monitoring systems installed at subsurface and/or at surface illustrate how operators can optimise the value of new and existing assets. Although much of the technology has been available for years, deployment in actual field operation is still a challenge. Several best practices are suggested to improve implementation success. The human component in this oil field revolution is important and cannot be under-estimated. The success of real-time enabled workflows can only occur if the workforce fully cooperates and buys-in to the solution. The inertia of legacy practices can derail the change management process if not considered early in the implementation.This paper discusses several industry approaches to product and service delivery of real-time enabled production workflows, and the various possible implementations. The commercial and physical implementations of these production workflows can range from remotely hosted solutions with no footprint on the operator premises, to fully integrated solution using and integrating legacy system of the oil and gas company. A segmentation of these approaches facilitates the selection process depending on parameters such as the size of the asset, legal constraints, availability of expertise. The value of the benefits of each of these approaches also provides a better understanding of the probable gains that may be achieved in the short to long-term time frame.
CARBON DIOXIDE AND CARBONATE CEMENTS IN THE OTWAY BASIN: IMPLICATIONS FOR GEOLOGICAL STORAGE OF CARBON DIOXIDE
Authors: Watson M.N. , Boreham C.J. , Tingate P.R.
Published: August 2017

Understanding CO2 source and carbonate cements in natural gas accumulations is important for predicting the behaviour of anthropogenic CO2 in a reservoir system. The Otway Basin offers an excellent opportunity to examine late CO2-derived cements as an analogue for mineralogical storage of CO2. Understanding Otway Basin diagenesis and carbonate cement distribution is also of great significance to petroleum production in the region.Elemental and textural examination of Otway Basin cements has identified five carbonates in reservoir rock from CO2-rich gas accumulations. These carbonates show an overall increase in Fe2+ and Mg2+ relative to the calcites in CO2-free reservoir rock, indicating cation derivation from CO2 interaction with labile minerals.δ13C isotopes of 2.18‰ to -6.7‰ PDB from late carbonate cements in reservoirs containing CO2, confirm an inorganic CO2 origin. 3He/4He gas isotopic ratios of R/Ra > 1 indicate a predominantly mantle input for the CO2-rich accumulations.Degassing of magma associated with Pleistocene to Recent volcanics is suggested as the dominant, CO2 source for the existing CO2 accumulations. CO2 influx from the magmatic source was rapid, and is the most analogous scenario to injection of anthropogenic CO2. Natural influx of CO2 and the opportunity for mineralisation of CO2 is variable, with CO2 dissolving some original carbonate and precipitation dependant on pH, ρCO2, and available cations. Positive mineralogical CO2 storage occurs in the Pretty Hill Formation, due to a higher content of labile lithic minerals, with ~36 kg/m3 of CO2 (~48 kg/m3 carbonate) stored in the Ladbroke Grove Field from the current CO2 phase. The Waarre Sandstone has negative mineralogical storage of CO2, with less carbonate than similar reservoir rock without CO2, and therefore more CO2 being released from dissolution of early carbonates.
IMPROVED INFLOW PERFORMANCE RELATIONSHIPS AND IMPROVED WELL BORE PERFORMANCE
Authors: Watson R.J.
Published: August 2017

The inflow performance relationship for oil proposed by Vogel (1968) and extended by Brown (1981) has been modified empirically to allow for variations in water cut and gas liquid ratio.The well bore performance of wells flowing or gas lifting continuously is known to be affected adversely by the separation of fluids at the eductor (tubing or annulus) intake. Performance is affected mostly in wells with large well bore storage.The design of the tubing intake also affects separation. A tubing intake that will reduce separation in flowing wells and increase separation in pumped wells has been designed and tested in a transparent model.A qualitative estimate of the gas separation efficiency of this device has been made. The estimate is based on the Ros (1961) flow regime map and on observations by Beggs and Brill (1973) that liquid hold-up increases with well deviation up to 40º. Further tests are warranted.Rod pump performance is analysed in detail. A spreadsheet allows comparison of pump capacity with well inflowperformance.Even at very low gas/liquid ratios, gas separation at the tubing intake affects significantly both single and two stage pump performance.
RECENT DISCOVERIES IN THE PYRENEES MEMBER, EXMOUTH SUB-BASIN: A NEW OIL PLAY FAIRWAY
Authors: Scibiorski J.P. , Micenko M. , Lockhart D.
Published: August 2017

Recent drilling by BHP Billiton Pty Ltd in WA-155-P(1) and WA-12-R, on behalf of its partners Apache Energy Ltd and INPEX ALPHA LTD, has resulted in the discovery of four oil fields in the southern Exmouth Sub-basin, namely Ravensworth, Crosby, Stickle and Harrison. These discoveries, together with the earlier discoveries made by West Muiron–5 and Pyrenees–2, define the Early Cretaceous Pyrenees Member play fairway.The Pyrenees Trend play was first conceived in 1999 following appraisal of the Macedon gas field (Keall, 1999), but the concept remained dormant until the integration of geological information with high quality 3D seismic data led to the recognition of hydrocarbon related seismic attributes in the postulated play fairway.Ravensworth–1 intersected a 37 m gross oil column below a 7 m gas cap in high quality Pyrenees Member sandstones beneath the regionally significant Intra- Hauterivian Unconformity. Ravensworth, located on a northeast–southwest trending fault terrace, is a complex structural-stratigraphic trap that relies on separate top, base and cross-fault seals. High quality 3D seismic data coupled with recent interpretation techniques were integral to its discovery. In particular, the quantitative interpretation of seismic amplitude populations was a key factor in decreasing exploration risk.The Ravensworth discovery was followed by successful exploration wells on the adjacent Crosby, Stickle and Harrison fault terraces. Four appraisal wells have since been drilled at the northern ends of the main discoveries.The oil in the Pyrenees Member discoveries is biodegraded, moderately viscous (8–11 cp) and heavy (18–19° API gravity). Methane-dominated gas caps were intersected in Ravensworth–1, West Muiron–5 and Pyrenees–2.The recent drilling and coring campaigns by BHP Billiton and others in the Exmouth Sub-basin have significantly advanced knowledge of the stratigraphy and depositional environments of the late Tithonian to early Berriasian Macedon, Muiron and Pyrenees Members of the lower Barrow Group. The lower Barrow Group is a third order sequence deposited rapidly in marine to fluviodeltaic environments in response to the breakup of Gondwana and the onset of active rifting along the West Australian margin.BHP Billiton and its joint venture partners are assessing the commercial viability of the Pyrenees Trend discoveries.
DEPOSITIONAL CONDITIONS OF THE NORTHERN ONSHORE PERTH BASIN (BASAL TRIASSIC)
Authors: Grice K. , Summons R.E. , Grosjean E. , Twitchett R.J. , Dunning W. , Wang S.X. , Bottcher M.E.
Published: August 2017

An oil-source rock correlation has been established for the northern onshore Perth Basin (Western Australia) based on unusual aromatic and polar biomarkers attributed ultimately to a green sulphur bacterial source. Several of these biomarkers have been identified throughout the entire Sapropelic Interval of a proven petroleum source rock intersected within a recently discovered marine Permian- Triassic Perth Basin borehole (Hovea–3) and several Perth Basin crude oils. Today, green sulphur bacteria live in the anaerobic zones of stratified lakes or in marine environments with restricted water circulation, where the upper sulphide limit coincides with the lower limit of oxygen. The presence of photosynthetic pigments and carotenoids of green sulphur bacteria, or their diagenetic alteration products in sediments provide unequivocal evidence for photic zone euxinic conditions in the paleowater column. Multiple lines of evidence for photic zone euxinia and euxinic depositional conditions for the Hovea–3 source rock have been obtained from biomarker analyses. Photic zone euxinia is usually associated with the widespread deposition of organic-matter-rich sediments that constitute important source rocks for petroleum deposits that are being exploited today. With the exception of the Perth Basin, such organic-matter-rich sediments are virtually absent from Upper Permian and Lower Triassic sediments globally. Several lines of evidence indicate localised surface ocean productivity may have played a key role in the deposition of a petroleum source rock at this location, although photic zone euxinia was globally more widespread during the Permian-Triassic Superanoxic Event.
A REAPPRAISAL OF THE CARBONIFEROUS STRATIGRAPHY AND THE PETROLEUM POTENTIAL OF THE SOUTHEASTERN BONAPARTE BASIN (PETREL SUB-BASIN), NORTHWESTERN AUSTRALIA
Authors: Gorter J.D. , Jones P.J. , Nicoll R.S. , Golding C.J.
Published: August 2017

A revision of the latest Tournaisian to Namurian stratigraphy of the Petrel Sub-basin is proposed following the recognition of a series of megasequences based on seismic profiles, well logs and new palaeontological information. In late Tn3c, turbidites of the Waggon Creek facies were overlain by a seal, the Milligans Formation (redefined) during the Chadian (V1a, V1b). A basal Arundian (V2a) regression, possibly driven by tectonics, deposited the Yow Creek Formation (new name) with incised valley fills. A basal Asbian (V3a) regression, deposited coarser grained clastics and limestones, the Utting Calcarenite (V3a), forming a possible local reservoir facies overlain by a regional seal, Kingfisher Shale (new name). An intra-Asbian (V3b) regression followed, possibly glaciogenic and/or tectonically driven, with the deposition of the Tanmurra Formation, dominantly coarse clastics, during the Asbian, forming reservoir facies with some source potential. Following a basal Brigantian unconformity, the Sandbar Sandstone (new name) formed a restricted ?aeolian facies, a potential local reservoir. An intra-Brigantian unconformity was followed by deposition of the carbonate Sunbird Formation (new name), generally a tight shelf edge carbonate (V3c), near Lacrosse–1 and Sunbird–1. A major basal Pendleian sea-level fall, probably glaciogenic, with major channel incision and erosion, was followed by Arnsbergian clastics with G. maculosa, the Arco Formation (new name) with basinal shales in clinoforms. The latest Arco Formation (earliest Pennsylvanian) was followed by a Late Namurian regression, and deposition of the Aquitaine Formation (new name), consisting of fluvio-deltaic siliciclastics, with minor marine influence, large scale channelling, potentially good reservoirs, and a regional upper shaly seal. This sequence is unconformably overlain by the basal Kulshill Group, which marked the onset of major Gondwanan glaciation.
COMPLEX MODIFIED THRUST SYSTEMS ALONG THE SOUTHERN MARGIN OF EAST TIMOR
Authors: Keep M. , Beck L. , Bekkers P.
Published: August 2017

Seismic structural interpretation of data across three basins along the southern coast of East Timor (the Suai, Beaco and Aliambata basins) reveals a complex deformation history dominated by intense thrust deformation within the thick (>3 km) Plio-Pleistocene sequence.Our interpreted deformation sequence of the clay-dominated rocks includes a series of south-directed, low-angle thrusts creating extensive thrust piles, and in places, antiformal stacks. These thickened piles exhibit later modification by crestal collapse. Rapid thickening destabilised the growing thrust packages, and caused regional-scale slumping of material into the Timor Trough to the south. The slumping disrupted thrust fronts and caused significant offset at the sea floor. Finally, shale injection and diapirism along the slump faults re-elevated some of the hanging-walls of the slumps.Oil and gas seeps, which occur mainly in southern East Timor, follow structural trends parallel to those offshore. Although sourced from proposed Triassic source rocks, uplift, exposure and subsequent leakage from these seeps probably occurred within the last 2 Ma, and possibly even later, co-eval with Plio-Pleistocene deformation. The proximity of oil seeps to fold and thrust deformation raises the possibility that additional Triassic or other Mesozoic section may occur at various structural levels within the deformed sedimentary wedge.
THE WHEATSTONE GAS DISCOVERY: A CASE STUDY OF TITHONIAN AND LATE TRIASSIC FLUVIAL RESERVOIRS
Authors: Palmer N. , Theologou P. , Korn B.E. , Munckton T.
Published: August 2017

The Wheatstone gas discovery is located 110 km northnorthwest of Barrow Island in the Dampier sub-basin, northwest Australia. The field comprises two non-conformable and interconnected reservoir units consisting of shallow dipping, Triassic fluvial sandstones, and an overlying Tithonian transgressive sand. These units are partially separated by Late Triassic to Early Jurassic sediments.The Tithonian sand reservoir is instrumental in hydrocarbon accumulation in the Greater Gorgon Area due to its unconformable connectivity to underlying Triassic reservoirs, and its ability to act as a thief zone. It is therefore a significant component in hydrocarbon entrapment. This paper discusses the transgressive Tithonian sand palaeogeography, and environment of deposition as a predictive tool of reservoir risk assessment and play fairway geography.This study compares and contrasts the rock properties of the latest Triassic sequences and proposes the palaeogeographic make up within the basin. A review of the reservoir properties has identified differences between units which may impact the formation evaluation approach used. The thinly bedded character of the latest Triassic sequences necessitated the use of a non-traditional formation evaluation model that has improved the accuracy of the wireline predicted reservoir properties. Acquisition of probe permeability data through conventionally cored intervals identified the limitations associated with standard core plug sampling procedures, and ensured better net reservoir definition through the sequence.
PETROLEUM POTENTIAL OF THE CEDUNA SUB-BASIN: IMPACT OF GNARLYKNOTS–1A
Authors: Tapley D. , Mee B.C. , King S.J. , Davis R.C. , Leischner K.R.
Published: August 2017

The Ceduna Sub-basin, located in the eastern Bight Basin, is one of the few frontier deepwater provinces in Australia whose hydrocarbon potential remains largely untested. The sediments of the sub-basin span an area of over 95,000 km2—comparable to the combined area of the Exmouth, Barrow and Dampier sub-basins on Australia’s North West Shelf. Prior to 2003, exploration wells had been drilled only on the present day shelf area of the sub-basin. The recent Gnarlyknots–1A well, drilled in May 2003 by the Woodside operated joint venture in EPP29, has provided the first calibration point in the under-explored deepwater area of the sub-basin.The well was the culmination of a basin analysis project that integrated results from prior drilling in adjacent areas, existing seismic surveys, regional gravity and magnetics interpretations, and a newly acquired 16,000 line km 2D seismic survey. Individual play elements of reservoir, seal, and hydrocarbon charge were analysed and combined to form play maps for key stratigraphic intervals. The Gnarlyknots prospect was chosen from more than 40 leads as the best location to test multiple play levels in an area interpreted pre-drill to be favourable for reservoir, seal, and charge.Gnarlyknots–1A confirmed the presence of several favourable play elements but failed to encounter commercial hydrocarbons. Excellent quality sandstone reservoirs, marine shale top seals and thermogenic hydrocarbon shows—indicating the presence of a hydrocarbon source rock in a mature kitchen area downdip—were all encountered in the well. The failure of the well is attributed to the absence of fault seal on the updip bounding fault of the drilled hanging wall structure. The implications of this well result for the prospectivity of the Ceduna Sub-basin have been analysed, and provide encouragement for Woodside to pursue future exploration programs in the region.
A SYSTEMATIC FAULT SEAL EVALUATION OF THE LADBROKE GROVE AND PYRUS TRAPS OF THE PENOLA TROUGH, OTWAY BASIN
Authors: Lyon P.J. , Boult P.J. , Watson M. , Hillis R.R.
Published: August 2017

Juxtaposition mapping of lithology onto the Ladbroke Grove Fault plane shows that the Pretty Hill Sandstone reservoir, which hosts a 90 m gas column, juxtaposes massive shale units in the hangingwall. Retention of the column at Ladbroke Grove can thus be attributed to favourable across-fault, reservoir-seal juxtaposition. The free water level (FWL) of the Ladbroke Grove column coincides with an abrupt change in strike of the fault from east–west to northwest–southeast. Fault re-activation risking using the FAST (Fault Analysis Seals Technology) technique indicates that the northwest–southeast striking segment of the fault is critically oriented within the in-situ stress field for reactivation, whereas the more east–west trending segment is associated with a relatively lower risk of fault re-activation. Hence recent slip along the northwest–southeast segment may have created permeable fracture networks along this part of the fault plane and thus limited the extent of the column to that bounded by the east–west trending fault segment. This hypothesis is supported by data on soil gases acquired across the fault which suggest that the fault is leaking CO2 across its northwest–southeast striking segment, but not across its east–west striking segment.The Pyrus Fault is not presently sealing by across-fault, reservoir-seal juxtaposition. The throw on the fault plane is sufficient to juxtapose the Katnook Sandstone in the hangingwall against the Pretty Hill Sandstone reservoir in the footwall, providing a sand-on-sand juxtaposition leak point at the structural apex of the trap. Fault re-activation along this fault is likely to have caused fracturing of any shale gouge veneer that may have been present along this sand-on-sand contact resulting in across-fault leakage of hydrocarbons into the Katnook Sandstone and leakage up the fault along permeable fracture networks. FAST predictions of fault re-activation show that the fault is critically oriented within the in-situ stress field for re-activation and soil gas measurements at the surface suggest the fault is leaking CO2.
SEABED SEDIMENT TRANSPORT AND OFFSHORE PIPELINE RISKS IN THE AUSTRALIAN SOUTHEAST
Authors: Li F. , Dyt C. , Griffiths C.M. , Jenkins C. , Rutherford M. , Chittleborough J.
Published: August 2017

The Australian seabed is influenced by extreme weather conditions of various types: cyclones, high tidal ranges, offshore currents and storm waves. In the past two centuries substantial progress in our understanding of the seabed and environmental conditions has been made by studies of the seabed sedimentology, hydrodynamics, and through habitat mapping. As part of the CSIRO Wealth from Oceans Flagship program the authors are involved in a new fiveyear study to investigate and predict the effect of possible climate change scenarios on the seabed in the next 50 years. Those changes will assess undersea infrastructure installations such as pipelines in a changed regime of seafloor stability, burial, erosion and abrasion.As an initial phase of this project the authors have extrapolated the current climatic conditions into the next 50 years. It was found that (under an extension of present day climatic conditions):the majority of terrigenous sediment carried down by major rivers (Murray River, Snowy River, Tamar River, etc) is trapped in the inland lakes or estuaries. Only a marginal fraction of fine grain sediment reaches the continental shelf;a high energy wave climate, significant tidal currents, and the frequent surges of wind-driven currents make the local seabed highly mobile and sensitive to the modern hydrodynamic changes. Both results imply that an exposed pipeline may suffer from local scour and fatigue damage due to oscillatory loads induced by vortex shedding behind the pipelines; andthere are several high risk zones in the region where turbidity current and submarine slope failure post a great threat to offshore pipelines.The next phase of the project will be to provide testable predictions of the changes under a variety of global warming scenarios.
THE TECHNICAL, ENVIRONMENTAL AND CULTURAL CHALLENGES OF DRILLING ON THE EDGE OF A NATIONAL PARK
Authors: Coleman J.E. , Franks L.N. , Berry M.D.
Published: August 2017

Magellan Petroleum, operator of the Palm Valley Gas Field, successfully drilled the Palm Valley–11 (PV–11) gas development well situated on aboriginal land adjacent to the Finke Gorge National Park, Central Australia. The drilling site was located within the Palm Creek catchment area, an environmentally significant and internationally renowned area which feeds the rare and endangered red cabbage palm (Livistona mariae).Although no commercial gas flow was encountered, the well was a success in terms of the technical, environmental and cultural heritage challenges faced during the 71-day drilling program.Several mitigation measures not generally required in petroleum drilling operations were incorporated in the PV–11 Drilling Program and Environmental Management Plan (EMP).This paper describes the Commonwealth and Northern Territory approval processes required to ensure all risks were identified and addressed; the challenges of drilling the PV–11 well using under-balanced techniques in difficult conditions; and the mitigation measures adopted to address these challenges.
TECTONOSTRATIGRAPHY AND POTENTIAL SOURCE ROCKS OF THE BASS BASIN
Authors: Blevin J.E. , Trigg K.R. , Partridge A.D. , Boreham C.J. , Lang S.C.
Published: August 2017

A study of the Bass Basin using a basin-wide integration of seismic data, well logs, biostratigraphy and seismic/sequence stratigraphy has resulted in the identification of six basin phases and related megasequences/ supersequences. These sequences correlate to three periods of extension and three subsidence phases. The complex nature of facies relationships across the basin is attributed to the mostly terrestrial setting of the basin until the Middle Eocene, multiple phases of extension, strong compartmentalisation of the basin due to underlying basement fabric, and differential subsidence during extension and early subsidence phases. The Bass Basin formed through upper crustal extension associated with three main regional events:rifting in the Southern Margin Rift System;rifting associated with the formation of the Tasman Basin; and,prolonged separation, fragmentation and clearance between the Australian and Antarctic plates along the western margin of Tasmania.The final stage of extension was the result of far-field stresses that were likely to be oblique in orientation. The late Early Eocene to Middle Eocene was a time of rifttransition and early subsidence as the effects of intra-plate stresses progressively waned from east to west. Most of the coaly source rocks now typed to liquid hydrocarbon generation were deposited during this rift-transition phase. Biostratigraphic studies have identified three major lacustrine episodes during the Late Cretaceous to Middle Eocene. The lacustrine shales are likely to be more important as seal facies, while coals deposited fringing the lakes are the principal source rocks in the basin.
GREENHOUSE GAS ISSUES—ONE FOR THE AUSTRALIAN TAXATION OFFICE?
Authors: Murray J.H. , Burns E.A.
Published: August 2017

In the 21st century we are constantly bombarded with issues on the need to do more to protect the environment and deal with greenhouse gas issues. The petroleum industry world-wide has come under fire for the emissions produced as a by-product of the petroleum refining industry and all primary producers and refiners must develop strategies to reduce atmospheric carbon dioxide emissions. While it is probably fair to say Australia’s appetite for production and consumption of natural gas or LNG is much more environmentally friendly than the days of fossil fuel sources such as coal, there is still a long way to go to minimise emissions in the industry.Global oil and gas companies operating in Australia are leading the way to develop ways to reduce greenhouse emissions. Two examples are Gorgon joint venture plans for carbon dioxide sequestration for its gas development project and perhaps BHP Billiton’s comments that it sees potential for similar sequestration into coal seams onshore Australia in Queensland, South Australia or New South Wales.The costs of projects to re-use or re-inject or sequestrate greenhouse gases are likely to be significant. But are these operating costs of the taxpaying entities in question and would they qualify for tax relief for income tax or petroleum resource rent tax purposes? This paper looks at some of the projects now underway in Australia to reduce greenhouse emissions in the petroleum sector and assesses whether the type of costs likely to be incurred in such projects might qualify for tax relief under existing legislation.
ACCOUNTING STANDARDS REFORM—WILL THERE BE HAVOC?
Authors: Williamson M.
Published: August 2017

Australia’s corporate regulatory authorities have been extensively lobbied during the last 10 years to move to adopt an international set of accounting standards that the major nations of the world have evolved. Following the establishment of the International Accounting Standards Board (IASB) in the UK, that body has moved to promulgate a broad range of accounting standards. Australia has been a member of the IASB from its early days.The IASB has moved to promulgate some accounting standards. The Australian Accounting Standards Board (AASB) has moved to adopt these same standards. In effect, the intent of those standards has been converted to Australian terms. The bulk of these new accounting standards (AASBs) will be effective for the first time to accounts of reporting entities for the years after 1 January 2005.The intention of the adoption of these standards has been to provide a consistent platform for the preparation of accounts in all of the major countries of the world. The expectation is to promote consistent reporting and more ready comparability between participants in various industries and between industries and from year to year.For a number of oil and gas listed companies, however, the short to medium-term is likely to produce the exact opposite in results and comparability terms. Accounting results for years prior to the adoption of the new AASBs will in certain circumstances bear results so dissimilar that their usage will be misleading.The conversion effort from the old standards to the new standards will involve considerable effort by all participants in the oil and gas industry; this should have started months ago.There will also be spin-off problems causing many legal documents, including borrowing agreements and performance bonus agreements that will need to be re-written. There will only be havoc in an administrative context if those oil and gas companies have not prepared themselves well and in a timely fashion. There may be financial havoc if the changes in accounting policies via the International Financial Reporting System (IFRS) make it difficult to raise new capital or cause problems under existing borrowing covenants.
BUYING AND SELLING PETROLEUM INTERESTS—IMPACT OF TAX CONSOLIDATION AND OTHER TAX REFORM MEASURES
Authors: Henderson R. , Franchina C. , Wiseman H.
Published: August 2017

The new tax consolidation system, together with a number of other recent tax reform measures, has lead to a paradigm shift in the way in which the acquisition and sale of petroleum interests are treated for taxation purposes in Australia. In an industry where ownership interests in exploration and production fields regularly change hands, it is important that senior executives and decision-makers have a clear understanding of the impact of the new tax rules.This paper focusses on the commercial impact of these tax changes and is aimed at executives in the oil and gas industry with commercial, technical, legal or financial responsibilities.Board members will also have an interest to ensure that the risks arising out of the new rules are adequately addressed, and that shareholder value is being preserved.
ENVIRONMENTAL UPDATE 2004
Authors: van Merwyk A.M. , Disney A.L.
Published: August 2017

This paper presents the highlights of development activity of 2004 for the petroleum industry within Australia. In the face of declining oil production within Australia there were few new oil field developments in 2004 (Exeter- Mutineer; Jingemia). The start up of liquids stripping at Bayu-Undan in the Timor Sea and other gas/condensate fields such as Apache’s Linda, however, helped to arrest the declining trend. The first oil fields that define a new oil province in the Exmouth Sub-basin were the subject of extensive appraisal programs and Woodside gave the green light for start of the A$1.48 billion Enfield development.The story for natural gas in 2004 is somewhat more buoyant with several developments in domestic supply around Australia, including coal seam methane (CSM) production on-stream on the east coast. The national pipeline grid extended with the opening of the A$500 million SEAgas pipeline between Port Campbell and Adelaide. Minerva gas production followed at the end of the year, leading the way for the approval of gas developments at Thylacine- Geographe (A$1.1 billion) and Casino (A$200 million) in the Otway Basin. The Yolla gas production platform was installed on site in the Bass Basin. Apache and Santos signed an agreement to supply gas from John Brookes, offshore Carnarvon Basin, and Woodside looked to Blacktip, in the Bonaparte, to supply gas to the Northern Territory.2004 was a cornerstone year for LNG. A new carrier was delivered to the NWS Joint Venture and gas flowed from the fourth LNG train for the first time. Deliveries under new contracts started to Japan and Korea and a major contract for supply was signed with China. Other potential LNG projects began significant appraisal programs at fields such as Scarborough on the NWS.
PROSPECTIVITY OF THE DEEPWATER GULF OF PAPUA AND SURROUNDS IN PAPUA NEW GUINEA (PNG)—A NEW LOOK AT A FRONTIER REGION
Authors: Jablonski D. , Pono S. , Larsen O.A.
Published: August 2017

Despite limited well control and paucity of seismic data, a regional study of the deepwater portion of the Gulf of Papua, Papua New Guinea (PNG), indicates a number of large structures at a variety of stratigraphic levels that are capable of holding significant volumes of hydrocarbons. The main structural elements east of the Fly River Platform the Pandora Ridge, Pandora Trough, Aure Trough, Port Moresby Trough and the northern portion of the Eastern Plateau were established during the Paleozoic and further enhanced by Late Cretaceous to Early Paleocene Coral Sea rifting in the southeast. Structuring in the region is mostly basement involved and extensional, and is overprinted by a later compressional pulse. Extensional and compressional regimes produce many potential traps. To date, exploration in the Gulf of Papua has been sporadic and mainly focussed in shallow water depths. The new reprocessed seismic data indicate the following Paleozoic to Recent plays, some of which contain multiple reservoir-seal pairs, sourced by non-marine and marine source rocks:extensional Paleozoic rift fault blocks;Upper Jurassic to Lower Cretaceous turbidites (Iagifu- Hedina-Toro sandstone equivalents);Campanian to Middle Paleocene Coral Sea synrift sandstone and basin floor fan equivalents (Pale/Barune Formations and equivalents);Middle Paleocene break-up unconformity fault blocks and intra-basinal highs;Upper Paleocene to Lower Eocene Pima Sandstone equivalent associated with the Middle Paleocene uplift and erosion;Oligocene to Lower Miocene lowstand deltas and turbidites;Miocene to Recent biohermal build-ups (possibly including a new limestone high, the Box Ridge, in front of the Pandora Ridge); Karstified Darai Limestone equivalent sealed by Aure Beds claystones;Miocene to Recent lowstand deltas and turbidites;Eocene to Pliocene stratigraphic onlaps flanking main structural highs; and,compressional plays associated with the Pliocene to Recent collision of the PNG and Pacific plates.
A NEW PERSPECTIVE ON EXPLORING THE COOPER/EROMANGA PETROLEUM PROVINCE—EVIDENCE OF OIL CHARGING FROM THE WARBURTON BASIN
Authors: Hallmann C.O.E. , Arouri K.R. , McKirdy D.M. , Schwark L.
Published: August 2017

The history of petroleum exploration in central Australia has been enlivened by vigorous debate about the source(s) of the oil and condensate found in the Cooper/Eromanga basin couplet. While early workers quickly recognized the source potential of thick Permian coal seams in the Patchawarra and Toolachee Formations, it took some time for the Jurassic Birkhead Formation and the Cretaceous Murta Formation to become accepted as effective source rocks. Although initially an exploration target, the Cambrian sediments of the underlying Warburton Basin subsequently were never seriously considered to have participated in the oil play, possibly due to a lack of subsurface information as a consequence of limited penetration by only a few widely spaced wells. Dismissal of the Warburton sequence as a source of hydrocarbons was based on its low generative potential as measured by total organic carbon (TOC) and Rock-Eval pyrolysis analyses. As most of the core samples analysed came from the upper part of the basin succession that has been subjected to severe weathering and oxidation, these results might not reflect the true nature of the Warburton Basin’s source rocks. We analysed a suite of source rock extracts, DST oils and sequentially extracted reservoir bitumens from the Gidgealpa field for conventional hydrocarbon biomarkers as well as nitrogen-containing carbazoles. The resulting data show that organic facies is the main control on the distribution of alkylated carbazoles in source rock extracts, oils and sequentially extracted bitumens. The distribution pattern of alkylcarbazoles allows to distinguish between rocks of Jurassic, Permian and pre-Permian age, thereby exceeding the specificity of hydrocarbon biomarkers. While no pre-Permian signature can be found in the DST oils, it is present in sequentially extracted residual oils. However, the pre-Permian molecular source signal is diluted beyond recognition during conventional extraction procedures. The bitumens that are characterised by a pre-Permian geochemical signature derive from differing pore-filling oil pulses and exhibit calculated maturities of up to 1.6% Rc, thereby proving for the first time the petroleum generative capability of source rocks in the Warburton Basin.
THE SIGNIFICANCE OF COAL SEAM GAS IN EASTERN QUEENSLAND
Authors: Baker G.L. , Skerman W.R.
Published: August 2017

The commercial production of coal seam gas [CSG] in Australia is only a decade old. Over the last 10 years it has become a significant part of the Australian gas industry, particularly in Queensland where about 31 PJ or 30% of all natural gas used in the State was recovered from coal seams in eastern Queensland. In 2005 CSG was expected to have supplied 55 PJ or 44 % of the eastern Queensland gas demand. The mining, mineral processing and power generations in northwest Queensland, serviced by the Carpentaria Gas Pipeline, will continue to use gas from the Cooper-Eromanga Basin.The CSG industry is reaching a stage of maturity following the commissioning of a number of fields while some significant new projects are either in the commissioning phase or under development. By the end of 2008 CSG production in Queensland is expected to reach 150 PJ per year, the quantity needed to meet Gas Supply Agreements for CSG that are presently in place.Certified Proved and Probable (2P) gas reserves at 30 June 2005 in eastern Queensland were calculated to be 4,579 PJ, of which 4,283 PJ were CSG. Gas reserves (2P) for eastern Queensland a decade earlier were less than 100 PJ with those for CSG being less than 5 PJ.The coal seam gas industry in both the Bowen and Surat basins—which includes major gas producers such as Origin Energy Limited and Santos Limited along with smaller producers such as Arrow Energy NL, CH4 Gas Limited, Molopo Australia Limited and Queensland Gas Company Limited—is now accepted by major gas users as being suppliers of another reliable source of natural gas.
GEOLOGICAL CONTROLS ON EXPLOITABLE COAL SEAM GAS DISTRIBUTION IN QUEENSLAND
Authors: Draper J. J. , Boreham C.J.
Published: August 2017

Methane is present in all coals, but a number of geological factors influence the potential economic concentration of gas. The key factors are (1) depositional environment, (2) tectonic and structural setting, (3) rank and gas generation, (4) gas content, (5) permeability, and (6) hydrogeology. Commercial coal seam gas production in Queensland has been entirely from the Permian coals of the Bowen Basin, but the Jurassic coals of the Surat and Clarence-Moreton basins are poised to deliver commercial gas volumes.Depositional environments range from fluvial to delta plain to paralic and marginal marine—coals in the Bowen Basin are laterally more continuous than those in the Surat and Clarence-Moreton basins. The tectonic and structural settings are important as they control the coal characteristics both in terms of deposition and burial history. The important coal seam gas seams were deposited in a foreland setting in the Bowen Basin and an intracratonic setting in the Surat and Clarence-Moreton basins. Both of these settings resulted in widespread coal deposition. The complex burial history of the Bowen Basin has resulted in a wide range of coal ranks and properties. Rank in the Bowen Basin coal seam gas fields varies from vitrinite reflectance of 0.55% to >1.1% Rv and from Rv 0.35-0.6% in the Surat and Clarence-Moreton basins in Queensland. High vitrinite coals provide optimal gas generation and cleat formation. The commercial gas fields and the prospective ones contain coals with >60% vitrinite.Gas generation in the Queensland basins is complex with isotopic studies indicating that biogenic gas, thermogenic gas and mixed gases are present. Biogenic processes occur at depths of up to a kilometre. Gas content is important, but lower gas contents can be economic if deliverability is good. Free gas is also present. Drilling and production techniques play an important role in making lower gas content coals viable. Since the Bowen and Surat basins are in a compressive regime, permeability becomes a defining parameter. Areas where the compression is offset by tensional forces provide the best chances for commercial coal seam gas production. Tensional setting such as anticline or structural hinges are important plays. Hydrodynamics control the production rate though water quality varies between the fields.
BLACKBACK SUBSEA A1A REMOTE WELL KILL
Authors: Williamson A.J.
Published: August 2017

Esso Australia Pty Ltd has recently completed a unique wellwork operation to secure the A1A well on its Blackback facility in Bass Strait. The Blackback facility consists of three subsea wellheads, linked in daisy-chain formation, sitting in 400 m of water depth. The field is approximately 19 km southeast of host platform Mackerel and 87 km from shore.The Blackback A1A well recently developed leak rates through the subsurface safety valve and production master valve which exceeded Esso’s internal acceptance criteria. Production rates on the A1A well did not justify an immediate workover to restore the integrity of the passing valves. Although there were no immediate environmental concerns, inadvertent damage to the wellhead had potential to create an environmental exposure, so the decision was made to kill the well temporarily until a workover opportunity arose.An innovative remote well kill procedure was developed, utilising the 23 km gaslift pipeline to pump kill fluids down to the well from host platform Mackerel. The procedure involved a unique and intricate shut-down procedure and pumping strategy. The main operational risks pre-identified and mitigated in the procedure included potential hydrate formation in the pipelines, over-pressure or blockage of the gaslift pipeline, and use of significant volumes of methanol for hydrate management.The Blackback well kill operation was executed to plan, with no safety, environmental or facility related issues. The A1A well remains in a killed state with positive overbalance, while start-up of the A3 well following the procedure was successfully executed. This achievement has opened new doors for conducting well kill operations on subsea facilities, with significant cost efficiencies when compared to the alternative—mobilisation of a floating drill rig.
GIPPSLAND BASIN GEOSEQUESTRATION: A POTENTIAL SOLUTION FOR THE LATROBE VALLEY BROWN COAL CO2 EMISSIONS
Authors: Gibson-Poole C.M. , Svendsen L. , Underschultz J. , Watson M.N. , Ennis-King J. , Ruth P.J. van , Nelson E.J. , Daniel R.F. , Cinar Y.
Published: August 2017

Geosequestration of CO2 in the offshore Gippsland Basin is being investigated by the CO2CRC as a possible method for storing the very large volumes of CO2 emissions from the Latrobe Valley area. A storage capacity of about 50 million tonnes of CO2 per year for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets are not compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–25. The potential injection targets are the interbedded sandstones, shales and coals of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO2 storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, low permeability marginal reservoir just below the regional seal providing additional mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient flow regime arising from production that enhances containment; and, long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO2. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from the use of new coal developments in the Latrobe Valley.
ILLITE/SMECTITE CLAYS PRESERVING POROSITY AT DEPTH IN LOWER PERMIAN RESERVOIRS, NORTHERN PERTH BASIN
Authors: Ferdinando D.D. , Baker J.C. , Gongora A. , Pidgeon B.A.
Published: August 2017

The appraisal well Hovea–2, drilled in July 2002, was the first well in the onshore Perth Basin to discover commercial volumes of gas in sandstone reservoirs of the Artinskian (Early Permian) High Cliff Sandstone sealed beneath basal shales and siltstones of the Irwin River Coal Measures. A drill stem test in this formation, in the interval 2,370–419 mMDRT (measured depth below rotary table), flowed gas to surface at 16.5 MMcfd. Thereafter, the High Cliff Sandstone became an important play for exploration in the basin; however, no additional discoveries have been made in this reservoir, even though it has been tested in another seven wells (Jingemia–1, Eremia–1, Kunzia–1, Corybas–1, Yardarino–6, Hakia–2 and Bunjong–1).In Corybas–1, drilled in 2005, this reservoir was found to be water bearing, but an 18 m core was taken within the topmost High Cliff Sandstone. This core provided important insights into the fluvial depositional environment of these sands. Importantly, porosity and permeability are highly variable within the reservoir, with some coarser grained beds retaining anomalously high porosity and permeability due to the coating of constituent quartz grains by illite/smectite that inhibited late stage quartz overgrowth. Study of this core along with core from overlying Irwin River Coal Measures indicates that there may be some facies control on the presence of the grain-coating clays in the High Cliff Sandstone, and that the fluvial to tidal facies are more likely to be an effective petroleum reservoir than the overlying fluvial/alluvial facies. This reservoir is the primary objective in the upcoming exploration wells Beharra Springs Deep–1 and Drakea–1, to be drilled in 2007.
LONGTOM—CONFIRMATION OF A NEW PLAY IN OFFSHORE GIPPSLAND
Authors: Lanigan K.P. , Bunn G. , Rindschwentner J.
Published: August 2017

The Longtom gas field was discovered in 1995, when the Longtom–1/ST1 wildcat well in the northern part of the offshore Gippsland Basin encountered dry gas in tight sandstones towards the base of the Latrobe Group, in what is now called the Admiral Formation of the Emperor Subgroup. In 2004 the Longtom–2/ST1 exploration well confirmed significant vertical and lateral extension of these prospective gas sands, and also provided very encouraging production test and core data. The recent Longtom–3 wells have demonstrated the viability of this new play by confirming significant lateral continuity of the thicker gas sands and demonstrating high gas flow rates. The history of the field’s discovery and appraisal illustrates how a multi-disciplinary and interactive approach, guided by innovative seismic inversion techniques and real-time petrophysical data, resulted in the successful planning and execution of the Longtom–3 drilling and evaluation program. The results of the wells and the outline of the field development plan illustrate how Longtom represents new production potential in this mature basin.
THE CUBE—A NEW VENTURES SUBSURFACE COMPUTE TECHNOLOGY CONCEPT
Authors: Shaw N.
Published: August 2017

With oil prices reaching record highs, exploration companies are eagerly venturing into the new and sometimes remote markets of Asia, Russia and North Africa. Commercial competition is fierce—leveraging a competitive advantage requires any and all means at a company’s disposal. The CUBE concept—combined unified business environment—provides computing infrastructure to new venture operations in dispersed global locations. Fast and efficient implementation of standardised infrastructure, applications and support help Shell New Venture business to hit the ground running, fast.