bluuebunny/crossref_metadata_2025 huggingface dataset:
IMPLEMENTATION OF THE BP CHOKE MODEL ON THE WOODSIDE OPERATED COSSACK PIONEER FPSO
Authors: Buchanan M. , Robinson P. , McCaffery C.
Published: August 2017

The choke model evolved from a BP campaign started in the early 1990s to improve production operating efficiency. The choke model is a software tool (Access 2000) designed to enable this process to be consistently applied across all BP’s producing assets. It enables losses to be identified and categorised relative to the system capacity or installed production capacity across four primary production chokes—the reservoir, wells, plant and the export system. The volume of losses (measured relative to the installed production capacity) is recorded and the source and cause of the loss are identified and categorised. The latter are then analysed for trends and opportunities are identified and prioritised for improvement. This paper describes the choke model and the collaboration between Woodside as Operator of the Cossack Pioneer, and BP, to implement the choke model and to improve production operating efficiency across the Joint Venture’s oil assets.The operating efficiency benefits and typical losses are analysed and discussed, learnings through the implementation process are described and improvements for the future are identified. Key conclusions and learnings from the implementation process include:the choke model is an operations improvement tool that helps support a production improvement process;definitions of Installed Production Capacity;need for standardisation of the sources and causes of losses (people interpret these differently); andthe need for consolidation of pre-existing reporting systems into one common database.
4D RESERVOIR GEOCHEMISTRY AS AN AID TO INTERPRETING PRODUCTION DYNAMICS, LEGENDRE FIELD, EASTERN DAMPIER SUB-BASIN
Authors: Davis R.C. , Leischner K.R. , Murray A.P. , Ryles P.G.
Published: August 2017

Reservoir geochemistry is a low cost, field development/appraisal tool resting on the principle that fluids isolated by flow barriers show slight compositional and/or isotopic differences. Such differences reflect subtle variations in charge history related to the location of the source kitchen and the source rock maturity at the time of expulsion, as well as post fill processes such as water washing and leakage. High resolution gas chromatography (HRGC), multi-dimensional gas chromatography (MDGC) and compound specific liquid and gas isotope analysis (CSIA) were performed on a time series of fluids, comprising stored oil from two drill stem tests, and produced fluids from six points in the Legendre field, Dampier Sub-basin, to investigate changes in fluid composition as production proceeded. The Legendre field contains high gravity (46° API), low viscosity oil, hosted in two culminations (North and South) in a thin, high quality clastic reservoir of Berriasian age. Fluids from different wells within the Northern accumulation are indistinguishable, indicating the oil is in communication and no compositional gradient exists. By contrast, compositional and isotopic differences between fluids from the Northern and Southern accumulations demonstrate that these pools are not in communication, and should therefore be treated separately from a development planning perspective.The differences in initial fluid compositions have been successfully used in conjunction with operational parameters to explain the increase in gas/oil ratio (GOR) of oil from Legendre South–2H that occurred after only 13 months of production. Comparison of pristine, preproduction separator samples with fluids collected after the observed increase in GOR, revealed that solution gas injected at Legendre West–1 has migrated rapidly into the southern part of the field. Integration of geochemical data with regional petroleum system concepts and a full 3D charge model has greatly assisted our understanding of these observations.
THE ASIA PACIFIC LNG MARKET: ISSUES AND OUTLOOK
Authors: Ball A.L. , Schneider K.M.
Published: August 2017

With rising natural gas demand and limited reserves in many Asia Pacific countries, LNG imports have emerged as an important gas supply source in the region. Rapid uptake of LNG has occurred in Japan, Korea and Chinese Taipei, and new and potential LNG markets are emerging in India, China, the Philippines, New Zealand and the north American west coast, among others. Growth in Asia Pacific LNG demand has encouraged the development of LNG export projects in the region, which has become the world’s largest LNG supplier, and the Middle East.Asia Pacific LNG imports are projected to nearly double by 2015. This will provide opportunities and challenges for LNG suppliers to the Asia Pacific market, including Australia. Competition to retain markets among existing LNG suppliers will be strong, although there will be a key role for new projects. Potential regional LNG supply capacity in the next 10 years is significant: Australia’s LNG export capacity has the potential to more than quadruple with a number of new projects scheduled to become operational.This paper reviews existing LNG demand and supply in the Asia Pacific region and provides an assessment of likely future developments in the market over the period to 2015, including the opportunities for the Australian LNG industry. The analysis in the paper is based on ABARE’s Asia Pacific LNG market: issues and outlook, released in November 2004, and excludes later developments.
WHY ARE THE INSURANCE UNDERWRITERS REVIEWING OUR EXPLORATION WELL RISKS?
Authors: Embury J.
Published: August 2017

The increased level of exploration in Australia and New Zealand has resulted in insurance underwriters taking a closer look at the region. A number of unfortunate onshore blowouts during 2003 and 2004 have focussed their examinations to determine whether these were symptomatic, regional problems or just one-off events. One of the tools being used to determine the level of exposure when insuring a well in Australia or New Zealand is the well risk review. The reviews typically involve an examination of a number of the drilling contractor’s key documents. This allows the reviewer to gain an understanding of the technical difficulty of the well, any environmental impact should an incident occur and the capabilities of all supervisor personnel and the match between the need to drill the well and the capability of the rig and the planning completed. It is the operator’s responsibility to comply with any recommendations that eventuate from the review and failure to do so may void the control of well insurance.Typically, the underwriters carry the cost of these reviews which have highlighted a possible issue with the competency of rig personnel as the industry grapples with the shortage of experienced people in an expanding market. To complicate the issue for the industry, many of the more experienced personnel are nearing retirement age and suitably experienced replacements are few and far between.The well risk review process should be seen as complementary to the State regulatory reviews and will, along with initiatives being undertaken by some participants in the industry, contribute to a safer industry with fewer incidents.
PORE PRESSURE PREDICTION BASED ON SEISMIC ATTRIBUTES RESPONSE TO OVERPRESSURE
Authors: Ciz R. , Urosevic M. , Dodds K.
Published: August 2017

A seismic attribute-based quantitative methodology for remote prediction of effective stresses is proposed in this study. The algorithm uses neural networks as a nonlinear interpolator between a set of seismic attributes to predict changes in differential pressure. This method is based on the relationships between specific seismic attributes and differential pressures, which were established through a series of laboratory tests. A number of ultrasonic elastic measurements simulating normal compaction, fluid expansion and tectonic mechanisms of overpressure were performed on reservoir sandstone and shale core samples. The effects of different stress paths on seismic attributes derived from experimentally recorded wavelets were investigated. Positive relationships were established between differential pressure and several seismic attributes for the first time in these tests. It has been found that instantaneous frequency, weighted mean frequency, instantaneous phase, instantaneous pseudo-Q factor, instantaneous bandwidth, instantaneous dominant frequency and autocorrelation function are sensitive to differential pressure changes. The relationships between those attributes and differential pressure follow Eberhart- Phillips’ stress-velocity empirical relationship. This implies that seismic attributes could be used for a quantitative prediction of overpressure. Moreover, our experimental results show that frequency-based seismic attributes exhibit a greater sensitivity to changes in differential pressure than does seismic velocity. The proposed methodology has been tested on a 3D seismic dataset from the North West Shelf of Australia. Predicted pore pressure values are in good agreement with available borehole data.
STRAIN LOCALISATION AND TRAP GEOMETRY AS KEY CONTROLS ON HYDROCARBON PRESERVATION IN THE LAMINARIA HIGH AREA
Authors: Gartrell A. , Bailey W. , Brincat M.
Published: August 2017

A strong relationship between the distribution of Late Miocene to recent (post-rift) strain, trap geometry and remaining oil columns is recognised in the heavily re-activated Laminaria High area. Preferential localisation of post-rift strain onto larger faults in the population resulted in the smaller faults accommodating progressively less strain with time. The strain localisation process appears to have protected some fault-bound traps with favourable geometries from breaching during fault re-activation, but promoted breaching of others. Where faults with high postrift strain are located at the crest of a trap, oil columns are not preserved. In contrast, where high strain post-rift faults are located down-dip of the trap crest, oil columns are preserved down to the depth of the critical high strain fault-top reservoir intersection. These observations suggest that a relatively simple assessment of the basic structural geometry of a trap may provide a first order approximation of trap integrity risks and could also be predictive of preserved hydrocarbon column heights.
GEOCHEMICAL EVIDENCE OF MULTIPLE HYDROCARBON CHARGES AND LONG DISTANCE OIL MIGRATION IN THE VULCAN SUB-BASIN, TIMOR SEA
Authors: Liu K. , Fenton S. , Bastow T. , Aarssen B. van , Eadington P.
Published: August 2017

Hydrocarbon accumulation and migration processes in the Vulcan Sub-basin, Timor Sea, were investigated using the Total Scanning Fluorescence (TSF) technique and phenol and carbazole abundances in both reservoired and inclusion oils. The TSF spectral signatures have delineated multiple groups of oils within the Vulcan Sub-basin, largely identifying with the different oil families previously identified by biomarkers and isotope data. An apparent correlation between diminishing carbazole concentration and increasing distance from the source kitchen was found in reservoired oils within the Vulcan Sub-basin, providing evidence for long distance oil migration of up to 80 km. In the southernmost part of the Vulcan Sub-basin a possible light hydrocarbon charge rich in benzene and other low-molecular-weight aromatic hydrocarbons is believed to be responsible for the observed anomalously high phenol concentrations in oils from the surrounding wells. A previously unknown, possibly a Cretaceous-or-younger, source kitchen may be present along the eastern margin of the Vulcan Sub-basin and was probably responsible for the palaeo oil accumulations in the Tancred and Osprey structures as revealed by the TSF spectral signatures and biomarkers from the fluid inclusion oils.
MORE WELLS, MORE OIL—A CASE STUDY OF RESERVES GROWTH IN THE KENMORE FIELD
Authors: Skinner J.E. , Altmann M.J. , Wadham T.H.
Published: August 2017

The Kenmore oil field in the Eromanga Basin of southwest Queensland was discovered in 1985. Since then, a further 32 wells have been drilled and more than 12.5 MMSTB of oil has been produced from the Birkhead Formation/Hutton Sandstone. Oil production over the last year has averaged 1,220 barrels per day totalling some 0.45 million stock tank barrels (MMSTB)Oil reserves in Kenmore were originally estimated at 2.2 MMSTB following the Kenmore–1 discovery well drilled in 1985. In the following 20 years, infill drilling, a 3D seismic survey, various reservoir studies and better -than-expected recovery efficiency, have steadily increased the ultimate recoverable reserves to the current estimate of 14.3 MMSTB.The growth of reserves at Kenmore is primarily attributed to better drainage of the complex reservoir framework within the lower Birkhead Formation resulting from recognition of the variable lateral connectivity of the reservoir. Due to the initial estimate of the ultimate field reserves being significantly smaller than now recognised and the resultant conservative drilling program, the economic value of the field was not maximised. This experience has implications for the ongoing development of the Kenmore field and suggests that other Birkhead/Hutton oil fields should be developed more aggressively to prevent history repeating itself.
MULTISTAGE HYDRAULIC FRACTURING WITH PRODUCTION INTERVALS—A PROMISING TECHNOLOGY FOR RESERVOIRS SUBJECT TO REVERSE FAULTING STRESS REGIMES
Authors: Rahman M.K.
Published: August 2017

The performance of hydraulic fracturing technology has not been so promising for some Australian tight-gas reservoirs. The existence of reverse faulting stress regimes (i.e. the vertical stress is the minimum one) in these reservoirs is found to be one reason among many others. Previous studies have established that the vertical hydraulic fracture initiated from a vertical well in a reverse faulting stress regime severely turns and twists to become horizontal while fracturing fluid is injected for further propagation of the fracture. This severely turned and twisted fracture impedes the fluid and proppant (engineered sand grains) injection and thus the fracturing job results in a short and constricted fracture. This is considered to be one of the major reasons for premature screen-outs that occur at extremely high-pressure on many occasions in the field, and the subsequent disappointingly low production rates. The aim of this paper is to present the results of an investigation with a model-scale gas reservoir to avoid this problem by carrying out the fracture treatments in a number of stages with production intervals. The basic mechanism that would allow the growth of a long, planar, productive fracture in such a manner is the production-induced stress change around the fracture tip. A simplified propped fracture configuration is modelled in a hypothetical small-scale reservoir with idealistic material properties. Production is simulated in time by varying different parameters and the production-induced stress changes are characterised by coupled fluid flow and deformation analysis. It is found from parametric results that the non-uniform reservoir pressure depletion induces a suitable stress state at the fracture tip for further planar propagation. The duration of production to induce the suitable stress state is found to be dependent on a number of parameters. The paper also highlights the implications and limitations of the concept for hydraulic fracturing in the mentioned reservoir conditions, and discussed further research directions.
DEMETER HIGH RESOLUTION 3D SEISMIC SURVEY—REVITALISED DEVELOPMENT AND EXPLORATION ON THE NORTH WEST SHELF, AUSTRALIA
Authors: Bennett K.J. , Bussell M.R.
Published: August 2017

The newly acquired 3,590 km2 Demeter 3D high resolution seismic survey covers most of the North West Shelf Venture (NWSV) area; a prolific hydrocarbon province with ultimate recoverable reserves of greater than 30 Tcf gas and 1.5 billion bbls of oil and natural gas liquids. The exploration and development of this area has evolved in parallel with the advent of new technologies, maturing into the present phase of revitalised development and exploration based on the Demeter 3D.The NWSV is entering a period of growing gas market demand and infrastructure expansion, combined with a more diverse and mature supply portfolio of offshore fields. A sequence of satellite fields will require optimised development over the next 5–10 years, with a large number of wells to be drilled.The NWSV area is acknowledged to be a complex seismic environment that, until recently, was imaged by a patchwork of eight vintage (1981–98) 3D seismic surveys, each acquired with different parameters. With most of the clearly defined structural highs drilled, exploration success in recent years has been modest. This is due primarily to severe seismic multiple contamination masking the more subtle and deeper exploration prospects. The poor quality and low resolution of vintage seismic data has also impeded reservoir characterisation and sub-surface modelling. These sub-surface uncertainties, together with the large planned expenditure associated with forthcoming development, justified the need for the Demeter leading edge 3D seismic acquisition and processing techniques to underpin field development planning and reserves evaluations.The objective of the Demeter 3D survey was to re-image the NWSV area with a single acquisition and processing sequence to reduce multiple contamination and improve imaging of intra-reservoir architecture. Single source (133 nominal fold), shallow solid streamer acquisition combined with five stages of demultiple and detailed velocity analysis are considered key components of Demeter.The final Demeter volumes were delivered early 2005 and already some benefits of the higher resolution data have been realised, exemplified in the following:Successful drilling of development wells on the Wanaea, Lambert and Hermes oil fields and identification of further opportunities on Wanaea-Cossack and Lambert- Hermes;Dramatic improvements in seismic data quality observed at the giant Perseus gas field helping define seven development well locations;Considerably improved definition of fluvial channel architecture in the south of the Goodwyn gas field allowing for improved well placement and understanding of reservoir distribution;Identification of new exploration prospects and reevaluation of the existing prospect portfolio. Although the Demeter data set has given significant bandwidth needed for this revitalised phase of exploration and development, there remain areas that still suffer from poor seismic imaging, providing challenges for the future application of new technologies.
PRESENT-DAY STATE-OF-STRESS OF SOUTHEAST AUSTRALIA
Authors: Nelson E. , Hillis R. , Sandiford M. , Reynolds S. , Mildren S.
Published: August 2017

There have been several studies, both published and unpublished, of the present-day state-of-stress of southeast Australia that address a variety of geomechanical issues related to the petroleum industry. This paper combines present-day stress data from those studies with new data to provide an overview of the present-day state-of-stress from the Otway Basin to the Gippsland Basin. This overview provides valuable baseline data for further geomechanical studies in southeast Australia and helps explain the regional controls on the state-of-stress in the area.Analysis of existing and new data from petroleum wells reveals broadly northwest–southeast oriented, maximum horizontal stress with an anticlockwise rotation of about 15° from the Otway Basin to the Gippsland Basin. A general increase in minimum horizontal stress magnitude from the Otway Basin towards the Gippsland Basin is also observed. The present-day state-of-stress has been interpreted as strike-slip in the South Australian (SA) Otway Basin, strike-slip trending towards reverse in the Victorian Otway Basin and borderline strike-slip/reverse in the Gippsland Basin. The present-day stress states and the orientation of the maximum horizontal stress are consistent with previously published earthquake focal mechanism solutions and the neotectonic record for the region. The consistency between measured present-day stress in the basement (from focal mechanism solutions) and the sedimentary basin cover (from petroleum well data) suggests a dominantly tectonic far-field control on the present-day stress distribution of southeast Australia. The rotation of the maximum horizontal stress and the increase in magnitude of the minimum horizontal stress from west to east across southeast Australia may be due to the relative proximity of the New Zealand segment of the plate boundary.
APPLICATION OF NUCLEONIC INSTRUMENTS IN SEPARATOR PROFILING: KUITO FPSO CASE STUDY
Authors: Beinart B.
Published: August 2017

The Kuito field lies in the offshore Cabinda Province, Angola. Kuito was Angola’s first deep-water oil and came on stream in December 1999. Kuito oil is produced via an FPSO. Kuito oil ranges 18–22 API. The FPSO has threephase, horizontal, gravity separation vessels that are used to separate oil and gas from unwanted produced water and solids prior to transportation. The production separators were designed with traditional, single point transmitters for measurement of the fluid interface and overall fluid levels. These were capacitance type instruments mounted inside the vessels in stilling wells.Following production start-up, separation problems began to emerge; these were manifested in numerous process upsets and shutdowns. Kuito oil can form emulsions quickly, and calcium naphthenate is produced at higher temperatures. If allowed to cool, it solidifies. The point instrumentation was unable to detect these emulsion and naphthenate layers resulting in the instrumentation becoming fouled and ceasing to function. The separators were operated ‘blind’, using tri-cocks located on the side of the vessel, and as the instrumentation was installed in stilling wells inside the vessel, it was impossible to maintain them without shutting down and depressurising the vessels. This paper describes how nucleonic profiling instruments were retrofitted to the vessels and shows how their operation was able to identify the different layers within the separators. This enabled the time of oil production to be increased and allowed the pro-active use of effect chemicals such as emulsion breakers and defoamers to be applied before the plant became unstable.
NATURAL ACCUMULATION OF CO2 IN COALS FROM THE SOUTHERN SYDNEY BASIN—IMPLICATIONS FOR GEOSEQUESTRATION
Authors: Faiz M.M. , Barclay S.A. , Sherwood N. , Stalker L. , Saghafi A. , Whitford D.J.
Published: August 2017

The southern Sydney Basin is an ideal natural analogue for CO2 geosequestration because of the widespread CO2 occurrence, extensive data sets available and general knowledge of gas distribution. The CO2 mainly occurs adsorbed in coal, incorporated into carbonate minerals and dissolved in formation water. On this basis, an area of ~900 km2 has been chosen for detailed examination.Gas in the coal seams of this area contain mainly CH4 and CO2, the CO2 content ranging from Calculations indicate that about 78 x 106 tonnes of CO2 are presently stored in coaly intervals in the study area. Assuming a storage capacity of 20 m3/t for these coal seams, the total CO2 storage capacity for the coaly intervals is ~880 x 106 tonnes. Using the study area as an analogue for enhanced coal seam methane production, 175 x 106 tonnes of CO2 could be stored, assuming a 50% CH4 recovery factor and an average CO2 sorption capacity 1.5 times that for CH4.
QUEENSLAND’S NEW PETROLEUM LEGISLATION—ITS IMPLEMENTATION AND OPERATIONAL CHALLENGES
Authors: Green P.M. , Matheson S.G. , Ralph K.D. , Thompson M.E. , Brain T.J.
Published: August 2017

up-to-date legislative environment for the petroleum industry in that State. The legislation specifically addressed issues in relation to upstream competition for exploration acreage and provided for storage of petroleum for a third party. It implemented the coal seam gas regime which provides a mechanism for the optimisation of the State’s coal seam gas and petroleum resources. The rights of existing holders of petroleum tenure were protected through the continuation of the Petroleum Act 1923 for selected authorities to prospect and petroleum leases. A new safety regime was implemented with the aim of addressing and managing risk rather than the emphasis being on the prescriptive compliance with Regulations. The safety regime covered all aspects of petroleum, from its production, transportation and use. The implementation of the new legislation required the development of work procedures to assist with uniform decision-making under the new legislation. This is particularly important owing to the continuation of the Petroleum Act 1923.
LEGAL ISSUES FOR COOPERATIVE AND CONCURRENT MINING AND PETROLEUM PRODUCTION
Authors: Minchinton J.S.
Published: August 2017

Increasingly, miners and petroleum producers are seeking rights of access to the same territory to explore for and extract their favoured resource, particularly in areas where there are commercial quantities of coal seam gas.Governments are encouraging miners and petroleum producers to maximise the extraction of their respective resources to supply the growing energy needs of Australian and international markets. These powerful drivers have led to legislation in several states including Queensland to encourage cooperative resource extraction by different parties operating in the same area.But while legislation provides an overall framework, significant issues are left to resource companies to resolve through the development of technical and commercial solutions for the joint extraction of resources with limited government involvement. Once a technical and commercial solution is agreed, a legal agreement is necessary to cement the arrangement.What legal issues need to be considered in agreements between miners and petroleum producers? Will exploration need to be addressed separately from production? How can flexibility be built into the agreement to allow for a change in circumstance? How can disputes be resolved and what role is there for courts and tribunals in disputes? Will standard boilerplate provisions be adequate for the agreement in hand?This paper seeks to answer some of these questions by highlighting the commercial and legal issues relevant to negotiations with particular reference to coordination arrangements for overlapping mining leases and petroleum leases under the Queensland coal seam gas regime.
PATHWAY TO PETROLEUM—EASING SKILL SHORTAGES THROUGH AN INDUSTRY INDUCTION PROGRAM
Authors: Starling S. , Sanders D. , Kemp R. , Haywood N.
Published: August 2017

To provide a pathway to employment, petroleum industry employers are sponsoring a standard induction program, delivered through a national network of training centres, which will be recognised as a passport for workers to gain access to oil and gas facilities.The Australian upstream petroleum industry faces many staffing challenges including: difficulties recruiting staff for new developments, competition from overseas projects for construction contractors, and the imminent retirement of an aging workforce. This growing employment demand and limited labour supply has created a strong competitive recruitment market that is characterised by skills shortages. Consequently, the industry is having to recruit workers from non-traditional labour pools and engage contractors whose workforce has limited oil and gas experience. Many of these workers are not familiar with petroleum industry processes, safety procedures, or environmental hazards.APPEA is supporting the development of the Induction Program to raise awareness and commence acquisition of these petroleum industry competencies; to facilitate wider staff recruitment; to up-skill contractors’ workforces; and, reduce repeated induction training while ensuring safety standards are maintained. The Induction Program will establish a qualification underpinned by a competency- based approach that is recognised as the minimum standard of entry level training for all workers in upstream petroleum workplaces. The Induction Program will be delivered through a national network of purpose-built Induction Centres designed to provide practical hands-on training in a simulated workplace environment.
MAXIMISING INDIGENOUS EMPLOYMENT IN THE OIL AND GAS INDUSTRY IN WESTERN AUSTRALIA
Authors: Hammond M. , Sanders D.C.
Published: August 2017

The skilled labour shortage facing the upstream oil and gas industry is encouraging companies who have already begun to examine ways of increasing the number of indigenous people in their workforce.It is common practice for companies to use fly-in flyout solutions to build a stable workforce in remote areas. While this suits many workers and operations, a simpler solution arguably would be to have a skilled workforce who works in their home region. Many resource companies are now placing a renewed emphasis on training indigenous people to take on roles in the oil and gas industry. A highly skilled local workforce will have benefits for industry with a reduction in logistical costs and an increase in retention rates.This paper describes the challenges facing companies which elect to develop those skills in a largely technically unskilled indigenous community. The paper uses a range of case studies drawn from company experience. It further showcases some success stories and describes where the industry might need to focus its efforts in order to achieve a more equitable training and employment outcome for Australia’s indigenous communities.
THE MOONIE–BRISBANE PIPELINE SPILL—ECOSYSTEM RECOVERY
Authors: Ames M.B. , Swann L.S. , Douglas J.E.
Published: August 2017

In March 2003, a rupture to the Moonie–Brisbane pipeline (MBP) at Lytton (Brisbane) resulted in a spill of 1.9 million litres (7,000 barrels) of crude oil to two hectares of land and 1.5 km of mangrove-lined drainage channels and small creeks near the Port of Brisbane.Due to the swift, coordinated response, no oil reached the Brisbane River and the bulk of the oil spilled was recovered. The response effort included isolation and evacuation of the affected area, containment and recovery of the crude oil and the development and implementation of a clean-up plan (which identified and prioritised response efforts in four primary areas).Following the emergency response a comprehensive program of remediation and monitoring was implemented, with focus on the recovery of the affected waterways and remediation of affected land.This paper describes the methods employed during the emergency response and their effect on the:initial impact on the environment;development and implementation of rehabilitation and remediation options; and,potential for ecosystem recovery.
MINDING THE GAPS—IDENTIFYING AND FILLING HOLES IN OFFSHORE OIL AND GAS INDUSTRY PROTECTIVE SECURITY
Authors: Oldfield J.T. , Horsington L.F. , Steel D.I.
Published: August 2017

The Federal Government, mindful of the pivotal importance of reliable supplies of oil and gas for the economic stability of the nation, has recently passed the Maritime Transport Security Amendment Act 2005. This introduces a security plan for Australia’s offshore oil and gas facilities aimed at combating the likelihood of physical attack by terrorists or other organisations.Here we discuss that security plan, and identify potential gaps of especial significance for the petroleum industry. Our focus is on the intelligence, surveillance and reconnaissance (ISR) capabilities represented by presently available technologies such as unmanned aerial vehicles (UAVs) plus commercial and allied-government satellites. In this discussion we dispel various myths (for example, the fiction of continuously-available real-time imagery).Next we consider the near-term future (next five-to-ten years) and analyse the improved ISR capabilities that will result from the burgeoning technologies being introduced during that period. These include the next generation of UAVs (including high-altitude long-endurance platforms) and also continuous (but limited resolution) imagery of the whole globe obtained from geostationary orbit. Again we identify potential security gaps that are pertinent from the perspective of the petroleum industry.On the basis of our capability gap identification we make recommendations with regard to evolving security concerns that the petroleum industry may wish to consider for submission to the Federal Government: given what ISR science, technology and engineering can deliver, what could be done on a whole-of-nation basis to optimise the defence of our offshore facilities?Finally, we outline the modelling and simulation capabilities that are available specifically to aid such organisations as the Department of Defence and Coastwatch in efforts to anticipate and thus efficiently and effectively ameliorate the potential for such attacks. These may well be of interest to the industry in that they underpin the analysis mentioned above, and inform what could and perhaps should be done to lessen the risk posed to the nation’s petroleum industry.
GEORGINA BASIN—AN EARLY PALAEOZOIC CARBONATE PETROLEUM SYSTEM IN QUEENSLAND
Authors: Draper J.
Published: August 2017

Queensland contains a number of carbonate-bearing basins which are under-explored for petroleum, but contain the elements of potentially economic petroleum systems. The oldest such basin is the Neoproterozoic to Ordovician Georgina Basin which straddles the Queensland-Northern Territory border and is traversed by the Ballera to Mount Isa gas pipeline.The basin developed across several major crustal blocks resulting in regional variations in deposition and deformation. Thick Neoproterozoic rocks of the Centralian Superbasin form the base of the sequence in apparently fault-bounded, extensional sub-basins. These rocks are generally tight and source rocks are unknown. The Cambrian to Ordovician rocks have the best petroleum potential with the most prospective part of the basin being the Toko Syncline. The Burke River Structural Belt is less prospective, but is worthy of further exploration. Basin fill consists of Cambrian and Early Ordovician rocks which are dominantly carbonates, with both limestones and dolostones present. In the Early to Middle Ordovician, the rocks became predominantly siliciclastic.The main phase of deformation affecting the Georgina Basin occurred in the Devonian as part of the Alice Springs Orogeny. The Toomba Fault, which forms the western boundary of the asymmetric Toko Syncline, is a thrust fault with up to 6.5 km of uplift. The angle of thrusting is between less than 40 degrees and up to 70 degrees. Rich, marine source rocks of Middle Cambrian age in the Toko Syncline are mature for oil except in the deepest part of the syncline where they are mature for dry gas. The deeper part of the Toko Syncline may be gas saturated.Potential hydrocarbon targets include large folds associated with fault rollovers, stratigraphic traps and faultbounded traps. Vugular, secondary porosity in dolostones offers the best chance for commercial reservoirs within the Ninmaroo and Kelly Creek formations and Thorntonia Limestone. There are also oolitic carbonates which may have good primary porosity, as well as interbedded sandstones in the carbonates with preserved porosity. Structurally controlled hydrothermal dolomite facies represent potential reservoirs. The dominantly siliciclastic Ordovician sequence is water flushed. Fracture porosity is another possibility (cf. the Palm Valley gas field in the Amadeus Basin). As the deeper part of the Toko Syncline appears to be gas saturated, there may be potential for basin-centred gas. Fine-grained carbonates and shales provide excellent seals. There has not been a valid structural test; although AOD Ethabuka–1 flowed 7,000 m3/d of dry gas, the well was abandoned short of the target depth.
PETROLEUM POTENTIAL OF THE GREAT SOUTH BASIN, NEW ZEALAND—NEW SEISMIC DATA IMPROVES IMAGING
Authors: Uruski C. , Kennedy C. , Harrison T. , Maslen G. , Cook R.A. , Sutherland R. , Zhu H.
Published: August 2017

Much of the Great South Basin is covered by a 30,000 km grid of old seismic data, dating from the 1970s. This early exploration activity resulted in drilling eight wells, one of which, Kawau–1a, was a 461 Bcf gas-condensate discovery. Three other wells had significant oil and gas shows; in particular, Toroa–1 had extensive gas shows and 300 m oil shows. Cuttings are described in the geological logs as dripping with oil. The well was never tested due to engineering difficulties, meaning that much of the bore was accidentally filled with cement while setting casing.In early 2006, Crown Minerals, New Zealand’s petroleum industry regulating body, conducted a new 2D seismic survey in a previously lightly surveyed region across the northern part of the Great South Basin. While previous surveys were generally recorded for five seconds, sometimes six, with up to a 2,500-metre-long cable, the new survey, acquired by CGG Multiwave’s Pacific Titan, employed a 6,000-metre-long streamer and recorded for eight seconds.The dataset was processed to pre-stack time migration (PreSTM) by the GNS Science group using its access to the New Zealand Supercomputer. Increasing the recording time yielded dividends by more fully imaging, for the first time, the nature of rift faulting in the basin. Previous data showed only the tops of many fault blocks. The new data show a system of listric extensional faults, presumably soling out onto a mid-crust detachment. Sedimentary reflectors are observed to seven seconds, implying a thickness of up to 6,000 m of section, probably containing source rock units. The rotated fault blocks provide focal points for large compaction structures. The new data show amplitude anomalies and other features possibly indicating hydrocarbons associated with many of these structures. The region around the Toroa–1 well was typified by anomalously low velocities, which created a vertical zone of heavily attenuated reflections, particularly on intermediate processing products. The new data also show an amplitude anomaly at the well’s total depth (TD) which gives rise to a velocity push-down.Santonian age coaly source rocks are widespread and several reservoir units are recognised. The reservoir at Kawau–1a is the extensive Kawau Sandstone, an Early Maastrichtian transgressive unit sealed by a thick carbonate-cemented mudstone. In addition to the transgressive sandstone target, the basin also contains sandy Eocene facies, and Paleogene turbidite targets may also be attractive. Closed structures are numerous and many are very large with potential to contain billion barrel oil fields or multi-Tcf gas fields.
PORE NETWORK MODELLING OF FORMATION DAMAGE DUE TO SUSPENDED PARTICLES
Authors: Gao C. , Rivero M. , Nakagawa E. , Rajeswaran T.
Published: August 2017

Formation damage caused by suspended particles takes place in various stages of drilling and production operations. The particles in drilling fluid, completion fluid, workover fluid, or injected water can clog the formation and cause severe reductions in productivity or injectivity. Related research has been conducted for years and the most widely used models are empirical, based on specific core flooding data. These models are easy to use; however, when they are applied to formations with different characteristics, the predictions are often rather poor.This work investigates a promising way to model formation damage at the pore level. Even though reservoir rocks have very different characteristics, they are all combinations of pore necks and pore bodies. In the proposed model, pore necks are represented by tubes and pore bodies are represented by globes to form a 2D network where particle deposition takes place. The pore size distribution is measured by porosimetry and assigned to the network. By adjusting the parameters of the pore necks and pore bodies, this pore network model can represent real porous media quite well. Surface deposition was considered to be the main mechanism of formation damage for small particles. The model was validated with lab test data and reasonable results were obtained. Compared with the empirical model, the pore network model could be applied to a much wider range of reservoirs.
RESERVOIR SIMULATION—UPSCALING, STREAMLINES AND PARALLEL COMPUTING
Authors: Asadullah M. , Behrenbruch P. , Pham S.
Published: August 2017

Simulation of petroleum reservoirs is becoming more and more complex due to increasing necessity to model heterogeneity of reservoirs for accurate reservoir performance prediction. With high oil prices and less easy oil, accurate reservoir management tools such as simulation models are in more demand than ever before. The aim is to capture and preserve reservoir heterogeneity when changing over from a detailed geocellular model to a flow simulation model, minimising errors when upscaling and preventing excessive numerical dispersion by employing variable and innovative grids, as well as improved computational algorithms.For accurate and efficient simulation of large-scale models there are essentially three choices: upscaling, which involves averaging of parameters for several blocks, resulting in a coarser model that executes faster; the use of streamline simulation, which uses a more optimal grid, combined with a different computational algorithm for increased efficiency; and, the use of parallel computing techniques, which use superior hardware configurations for efficiency gains. With uncertainty screening of various multiple geostatistical realisations and investigation of alternative development scenarios— now commonplace for determining reservoir performance—computational efficiency and accuracy in modelling are paramount. This paper summarises the main techniques and methodologies involved in considering geocellular models for flow simulation of reservoirs, commenting on advantages and disadvantages among the various possibilities. Starting with some historic comments, the three modes of simulation are reviewed and examples are given for illustrative purposes, including a case history for the Bayu-Undan Field, Timor Sea.
AUSTRALIA’S GAS FUTURE—A RESEARCH AND DEVELOPMENT PERSPECTIVE
Authors: Whitford D. J. , Pullar J.
Published: August 2017

Australia’s large natural gas resource offers the prospect of a secure and competitive supply of transport, domestic and industrial fuels, lower emissions and an opportunity for significant wealth generation. Although the use of gas is growing fast, there remain significant technological hurdles that must be overcome before its full potential is realised. Many of the technical issues have a distinctive Australian dimension that demand local solutions—we cannot necessarily rely on imported technology.In consultation with industry, government and other research and development providers, CSIRO has developed a gas technology roadmap that provides the basis for an integrated research program in support of the Australian gas industry. The roadmap addresses the needs of both the conventional and unconventional gas industries and covers the value chain from exploration, production and processing, to utilisation and end use.In the context of ensuring a reliable and secure supply of competitively priced gas, two research streams have been identified, focussing on accessing remote conventional gas that is economically stranded, and unlocking Australia’s large unconventional gas resources to supply the southeast quadrant. Gas is an intrinsically cleaner fuel than oil or coal in terms of CO2 emissions and specific research opportunities in geosequestration, gas-based alternative fuels and distributed energy have been identified.Gas in the form of LNG is a fast-growing export industry enhancing Australia’s position as a leading energy exporter. There are opportunities for research and development to contribute to LNG, gas-to-liquids (GTL) fuel conversion as well as the greater use of gas for large-scale resource developments. Given the diversity and range of research opportunities, Australia has the potential to become a global leader in gas technologies with the chance to grow knowledge-based exports in addition to the export of rawfuels and embedded-energy products.
KEEPING IT GOING—LONGFORD COMBINAIRE REFURBISHMENT
Authors: Norman G.M.
Published: August 2017

ExxonMobil Australia Pty Ltd’s subsidiary, Esso Australia Resources Pty Ltd (ExxonMobil), is undertaking a refurbishment program on the critical combinaire cooling units at its Longford Gas Plant 1. The combinaires are combination air-cooled heat exchangers with evaporative cooling supported on a large concrete structure. The functions performed include gas treating, inlet gas cooling, distillation reflux and condensate cooling.The Longford combinaire units have already been in operation in excess of 30 years and the facility will be required to operate for many more years, given the significant reserves remaining in Gippsland. The combinaire units provide the central cooling duties in both the Longford crude stabilisation plant and Gas Plant 1. Shutdown of these units has a major impact on the plant processing capacity for both oil and gas. An in-depth understanding of forecast market demand, processing requirements and interaction of the process units throughout the Longford facility has enabled the identification of discrete annual periods when certain sections of the combinaire unit can be brought offline.The refurbishment campaign was developed to systematically refurbish sections of the combinaire unit that were not at full capacity seasonally. Critical to achieving the tight timelines is having timely delivery of refurbished and new components to site. This is being achieved through close collaboration with numerous vendors and initiatives such as setting up a local workshop for tube bundle refurbishment.The combinaire refurbishment campaign is on track to meet the target completion date and continues with minimal impact on Bass Strait production of oil and gas. Success is being achieved through detailed analysis across a range of disciplines and the application of a design-one, build-multiple philosophy. A large and complex project being undertaken whilst keeping the plant going.
LONG ISLAND POINT FRACTIONATION PLANT FACILITIES LIFE EXTENSION
Authors: Keen G.R. , Sethi M.G.
Published: August 2017

ExxonMobil Australia Pty Ltd’s subsidiary, Esso Australia Resources Pty Ltd (ExxonMobil), and BHP Billiton jointly own and operate an LPG fractionation facility at Long Island Point, near Hastings in Victoria. This facility began operating in 1970 as part of the overall development of Gippsland oil and gas resources. The facility had a nominal design life of 30 years; however, the facility will be required to operate for many more years, given the significant gas reserves remaining in Bass Strait. A plan was developed to identify and progress plant facility upgrades to ensure continued, safe operation to life end. Nine separate projects with a total value in excess of A$250 million were developed and are now in various stages of progress. The key projects include: refrigerated LPG storage tank refurbishment, fire system upgrade, a new control room and control system, and plant emergency shutdown system upgrades. These projects focus on achieving high standards of safe operations and long-term reliability through application of advances in technology to ready the facilities for their remaining life.