bluuebunny/crossref_metadata_2025 huggingface dataset:
Onshore Petroleum Centre of Excellence—collaboration by industry partners, government and TAFE to deliver trained staff for an expanding onshore petroleum industry
Authors: Bettina Venner , Chris Wood , Kevin Welsh , Fiona Mossman , Paul Goiak , Alison Roberts , Anthony Behn
Published: August 2017

Santos, Beach Energy and Senex Energy are collaborating with the SA Government and TAFE SA to set up a hub for onshore oil and gas training in Adelaide. The training facility provides a fully immersive simulated oil and gas production environment, as well as static equipment displays for demonstration and educational purposes. It is used for technical training, including safety, environmental and sustainable operational principles and key maintenance activities.
The simulated production environment includes different pump types, gas compressors, a pig launcher and receiver, gas metering skid, field separator and small tanks, as well as associated pressure safety valves, flow valves and other instruments. Water is used to simulate oil and air is used to simulate gas flow.
The static equipment display includes various valve types, flanges and a wellhead. Santos, as operator of the SA Cooper Basin joint venture (of which Beach Energy is a member), has committed significant oil and gas production and mechanical equipment, engineering design, transportation and installation of the training facility’s equipment.
The SA Government, Senex Energy and Beach Energy have committed funding for fit-out, capital works and the running of the facility for the first two years. Industry partners GPA Engineering, Fyfe Engineering, Logicamms, Veolia Environmental Services, Toll Energy, Transfield Services, Ottoway Engineering, Bureau Veritas, MRC Group, Max Cranes, Whitham Media Australia, Inductabend, Toyota Australia, James Walker Australia, Coventry Fasteners, Centralian Controls and Central Diesel are providing expertise and services. The training facility officially opened on 16 February 2015
Is there a benefit to throwing the kitchen sink at geotechnical studies in an exploration phase?
Authors: Shadlow James , Craig Adam , Christiansen David
Published: August 2017

In short, yes. This case study illustrates that the application of a thorough geotechnical workflow incorporating many new and advanced techniques can assist in exploration business case decision making. Is an exploration drilling decision made lightly?
A workflow incorporating 3D seismic processing, AVO inversion and stratigraphic framework studies involving high-resolution biostratigraphic and chemostratigraphic analyses was used to assess the prospectivity of an exploration permit near giant gas fields in the offshore Northern Carnarvon Basin. The primary reservoir is the prolific Triassic Mungaroo Formation fluvio-deltaic sediments, and secondary reservoirs include mid-Jurassic marine sands.
3D seismic reprocessing xcombined a newly acquired broadband seismic dataset into a multi-survey multi-azimuth PSDM volume that conditioned data for input to an AVO inversion. New petrophysics and rock physics analysis and modelling on regional well data were then calibrated with the AVO inversion to statistically derive lithology and fluid prediction volumes. These data were used in conjunction with reservoir paleo-stratigraphy studies to derive a subsurface model for reservoir distribution and hydrocarbon prediction.
A two-stage risking process was applied to each prospect that objectively applied risk based on the seismic amplitudes. This enabled a more accurate risked-volume assessment, combined with the ability to assess a prospect portfolio covering different plays.
The resultant interpretation identified issues with interpretations made on vintage data that would not have been easily identified without undertaking these studies. The integration of these assessments resulted in an unfavourable exploration drilling business case and a decision not to renew the permit.
Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures
Authors: Pokalai Kunakorn , Kulikowski David , Johnson Raymond L. , Haghighi Manouchehr , Cooke Dennis
Published: August 2017

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment.
In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures.
The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.
Front end loading: misunderstood or misapplied?
Authors: Newman David , Begg Steve , Welsh Matthew
Published: August 2017

Historically, oil and gas projects have struggled to achieve promised outcomes. Research has demonstrated that a good predictor of project outcomes is the level of front end loading (FEL) achieved at the final investment decision (FID). Specifically, projects with high levels of FEL have more predictable costs, shorter schedules and better production attainment.
Anecdotally, however, the application of FEL within the industry is patchy, with many companies advocating its use but allowing projects to pass decision gates with incomplete levels of FEL.
To understand why this occurs, the authors have interviewed more than 30 senior personnel from a range of oil and gas companies, asking them a series of questions about their understanding and acceptance of FEL. Those interviewed had significant experience, averaging more than 25 years in oil and gas, and more than 20 years’ experience on opportunities and projects.
Results suggest that, while FEL is highly regarded and the concept is well understood, it is not always applied appropriately. It is used as a final hurdle—checking the level of FEL just prior to the FID—rather than as a guide from the early stages to determine what work needs to be focused on to achieve a good FEL score. Furthermore, lower FEL benchmark scores are often overridden by expert judgment, justified by a project’s unique characteristics, allowing it to proceed.
This approach, focusing on the specific attributes of a project and ignoring general effects or predictive models such as FEL benchmarking, is referred to as taking an inside view and is known to produce inferior results, such as cost and time overruns. The authors argue that a stricter application of FEL and benchmarking predictions, integrating it from the early stages of projects and allowing overrides only in truly exceptional cases, will produce superior outcomes.
Seismic petrophysics focused case study for AVA modelling and pre-stack seismic inversion
Authors: Zeb Jahan , Rajput Sanjeev , Ting Jimmy
Published: August 2017

Hydrocarbon reservoirs are characterised by integrating seismic, well-log and petrophysical information, which are dissimilar in spatial distribution, scale and relationship to reservoir properties. Well logs are essential for amplitude versus offset (AVO) modelling and seismic inversion. The usability of well logs can be determined during wavelet estimation, seismic-to-well ties, background model building, property distribution for inversion, deriving probability density functions and variograms, offset-to-angle conversion of seismic data, and many other processes. For the implementation of seismic inversion workflows, accurate and geologically corrected compressional-sonic, shear-sonic and density logs are necessary. Preparing the logs for quantitative interpretation becomes challenging in a real-field environment because of bad borehole conditions including washouts, uncalibrated and variability of logging tools, invasion effects, missing shear logs and change of borehole size. Conventional petrophysical analysis is usually restricted to the reservoir interval, the calculation of reservoir versus non-reservoir (including sands or shales), and log corrections for smaller intervals; in contrast, seismic petrophysics encompasses the entire geological interval, calculates the volume of multi-minerals, incorporates boundaries between non-reservoir and reservoir, and often includes the prediction of missing compressional and shear-sonic for AVO analysis.
A detailed seismic petrophysics analysis was performed for amplitude versus angle (AVA) modelling and attributes analysis. To perform the AVA modelling, a series of forward models in association with rock physics modelled fluid-substituted logs were developed, and associated seismic responses for various pore fluids and rock types studied. The results reveal that synthetic seismic responses together with the AVA analysis show changes for various lithologies. AVA attributes analysis show trends in generated synthetic seismic responses for various fluid-substituted and porosity logs. Reservoir modelling and fluid substitution increases understanding of the observed seismic response. This paper describes detailed data analysis using various techniques to confirm the rock model for petrophysical evaluation, rock physics modelling, AVA analysis, pre-stack seismic inversion, and the scenario modelling applied to the study of an oil field in Australia.
New insights into the petroleum prospectivity of the Browse Basin: the results of a multi-disciplinary study
Authors: Rollet Nadege , Grosjean Emmanuelle , Edwards Dianne , Palu Tehani , Abbott Steve , Totterdell Jennifer , Lech Megan , Khider Kamal , Hall Lisa , Orlov Claire , Nguyen Duy , Nicholson Chris , Higgins Karen , McLennan Stephanie
Published: August 2017

The Browse Basin hosts large gas accumulations, some of which are being developed for conventional liquefied natural gas (LNG). Extensive appraisal drilling has been focused in the central Caswell Sub-basin at Ichthys and Prelude, and along the extended Brecknock-Scott Reef Trend; whereas elsewhere the basin remains underexplored. To provide a better understanding of regional hydrocarbon prospectivity, the sequence stratigraphy of the Cretaceous succession and structural framework were analysed to determine the spatial relationship of reservoir and seal pairs, and those areas of enhanced source rock development.
The sequence stratigraphic interpretation is based upon a common North West Shelf stratigraphic framework that has been developed in conjunction with industry, and aligned with the international time scale. Sixty key wells and 2D and 3D seismic data have been interpreted to produce palaeogeographic maps and depositional models for the Cretaceous succession. Geochemical analyses have characterised the molecular and stable isotopic signatures of fluids and correlated them with potential source rocks. The resultant petroleum systems model provides a more detailed understanding of source rock maturity, organic richness and hydrocarbon-generation potential in the basin. The model reveals that many accumulations have a complex charge history, with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, including the Lower–Middle Jurassic J10–J20 supersequences (Plover Formation), Upper Jurassic–Lowermost Cretaceous J30–K10 supersequences (Vulcan Formation), and Lower Cretaceous K20–K30 supersequences (Echuca Shoals Formation). Burial history and hydrocarbon expulsion models, applied to these Jurassic and Cretaceous supersequences, suggest that numerous petroleum systems are effective within the basin. For example, hydrocarbons are interpreted to have been generated from several source pods within the southern Caswell Sub-basin with migration continuing onto the Yampi Shelf, an area of renewed exploration interest.
Australian onshore petroleum acreage release 2016
Authors: Gorton Justin
Published: August 2017

This paper compiles material from state and territory jurisdictions describing the location and resource potential of Australian onshore and coastal waters acreage to be made available for petroleum exploration in 2016. The Australian state and territory governments continue to support investment in the petroleum industry through the annual provision of land for exploration, which is promoted nationally and internationally. Technical assessments are provided with the release, which detail the potential for conventional and/or unconventional resources. The level of assessment will depend on exploration maturity, but may include a description of the geological setting, review of exploration history, summary of key results, and subsurface maps/sections. In addition to this, any updates on recent upstream developments and government initiatives, as well as present and future policy directions that relate to onshore petroleum exploration, may be described, particularly for jurisdictions that are not making land available this year. With global demand for gas—led by Asia—expected to grow at 2.6% annually between 2015 and 2025, investing in Australia’s petroleum and gas industry presents a significant opportunity to supply into this growing market.
Industry partnerships in addressing mental health
Authors: James Carole , Kelly Brian , Considine Robyn , Tynan Ross , Skehan Jaelea , Rich Jane
Published: August 2017

Mental health issues are widespread across Australia, with the most common mental illnesses experienced by 20% of the population in any 12-month period. While no industry-specific data exists, general national population data suggests that all employers are managing workers affected by mental illness.
Workplaces are ideally placed to prevent mental health problems, promote mental health, and support a person with mental illness. Investing in strategies to support mental health in the workplace has been associated with improvements in productivity, job satisfaction and significant returns on investment.
This extended abstract discusses approaches to addressing mental health in the resources sector and reports on industry engagement, partnership with researchers from The University of Newcastle, and research into targeted interventions. A range of partnership activities included the development of a framework to support mental health in the workplace—a Blueprint for Mental Health and Wellbeing—and various workplace strategies to address mental ill-health and wellbeing.
Discussion centres on the feasibility, acceptability and effectiveness of a multi-component mental health program that aims to promote:

mental health awareness to employees;
a peer-based support model;
education to supervisors regarding the management of staff experiencing mental health problems; and,
a review of organisational policy.

Research in the coal-mining sector has demonstrated that through industry partnership, appropriate interventions can be developed and implemented that result in policy and practical changes that better the health and wellbeing of employees.
Simplicity from complexity
Authors: Thomas Howard
Published: August 2017

Joseph Tainter suggests that empires collapsed because they became too complex. In early days, the order (and complexity) the rule of empire brought was positive; the law of diminishing returns reduced the marginal value until it disappeared completely. Tainter says collapse is a natural simplification.
Peter Drucker describes a clear trend of growth in management throughout the 20th century and pursuit of risk avoidance through increased control. Moore's Law and Wirth's Law describe the growth in information technology though the 21st century. The work of Edward Hess suggests few companies have grown in excess of GDP for extended periods, yet the markets demand growth.
This extended abstract introduces the contagion of complexity to describe the cumulative effect of management growth, IT growth, and the pursuit of growth above GDP.
There is a need to identify when the value of complexity turns negative, and to innovate before companies experience deterioration in productivity. Industry is now producing more, but at the same time its complexity is increasing.
The common denominator of best practice is all about making things simpler, enabling competent people to do their job with a minimum level of bureaucracy. When IT was introduced it seemed to promise to allow people to work less and have a better work-life balance. If that promise is to be believed, and IT is to be used effectively to enable performance instead of control performance, there is still time to simplify and avoid the point of negative inflexion.
How an integrated multi-discipline approach to ALARP assessments can yield production increases while minimising HSE risk
Authors: Bonini Jim , Muir Lucy , Blackmore Steven
Published: August 2017

Demonstration that risks are reduced to as low as reasonably practicable (ALARP) is a fundamental element of safety and environment regulation in the Australian oil and gas industry. The principle is well established, and offers operators relative flexibility in designing and managing their operations when compared to the more prescriptive regime adopted in other countries, such as the US.
The approach, however, to building the ALARP case invariably differs between safety, environmental, and technical disciplines within oil and gas operators, leading to conflicting outcomes and sub-optimal solutions, which in turn can hamper production output and efficiency.
A recent change in offshore regulations requires operators to focus on reducing overall environmental impacts from produced water through the ALARP principle, rather than by a prescribed limit. Through options screening, detailed technical studies, and consideration of environment and health and safety trade-offs, a robust ALARP position can be achieved, which yields increased production and efficiency, and reduced environmental impact, health and safety risk and associated cost.
Drawing on recent project case studies with offshore oil and gas operators in Australia, the authors present best practices in the development of integrated ALARP cases for activities including produced water treatment and decommissioning.
Determining the impacts of coal seam gas extraction on water-dependent assets
Authors: Post David , Baker Peter , Barrett Damian
Published: August 2017

Many Australians, particularly in rural areas, are seeking clear scientific information about the potential impacts of coal seam gas production on groundwater and surface water across the country. In response to the resultant community concern, the Australian Government commissioned an ambitious multi-disciplinary program of bioregional assessments to improve understanding of the potential impacts of coal seam gas (and large coal mining) activities on water-dependent assets across six bioregions in eastern and central Australia.
Delivered through a collaboration between the Department of the Environment, the Bureau of Meteorology, CSIRO, and Geoscience Australia—and including close engagement with natural resource management and catchment management organisations, coal resource companies, Indigenous peoples and state governments—the results will allow coal resource companies, governments, and the community to focus on the areas where impacts may occur so that these can be minimised.
Key findings of the program will be presented with specific reference to the potential impacts on water-dependent assets due to CSG development by Metgasco and AGL in the Clarence-Moreton and Gloucester regions, respectively.
A risk management approach to safe mooring systems in Australia
Authors: Sullivan Paul
Published: August 2017

In March 2015, during cyclone Olwyn, a mobile offshore drilling unit (MODU) experienced a mooring failure and loss of position event. The MODU was blown some three nautical miles off location in the vicinity of subsea and surface infrastructure.
There are serious safety, environmental, financial, and reputational risks that can be presented by a loss of mooring position.
In response, NOPSEMA hosted a workshop with members of APPEA, the International Drilling Contractors Association (IADC) and with mooring contractors with a view to collectively improve the management of risks associated with the mooring of MODUs in Australia’s tropical waters, both in the short and longer term. Following this workshop, NOPSEMA issued an Information Note for the 2015/16 cyclone season, describing the regulators’ expectations of industry duty holders in respect of MODU mooring system management.
At the same time, APPEA’s Drilling Industry Steering Committee (DISC) members aligned on the key principles underpinning a MODU mooring system approach.
In late 2015, the APPEA DISC members commissioned a working group to develop a guidance framework for MODU mooring management in Australian tropical waters. DISC aims to work closely with industry partners such as IADC and specialist mooring contractors in the development of this framework.
DISC has tasked the working group to have the guidance framework ready for the 2016/17 cyclone season, and for presentation at the 2016 APPEA Conference.
The completed case study, presented at the APPEA Conference, provides an excellent example of a goal-setting and continuous improvement regulatory regime working as designed and intended.
Estimation of uncertainties in fault lateral positioning on 3D PSDM seismic image: an example from the North West Shelf
Authors: Birdus Sergey , Ganivet Vincent , Artemov Alexey , Teakle Ray , Phythian Paul
Published: August 2017

This extended abstract presents a two-step sequence to estimate uncertainties in lateral positioning of fault planes on 3D PSDM (pre-stack depth migration) seismic images. This analysis can be applied to any localised detail on a seismic image but, in the majority of geological settings, it is most important for the faults.
The first step provides an approximate evaluation of what causes the uncertainties, how the uncertainties are distributed in a 3D space, and what to expect within target zones. The authors assume that every complex detail within a 3D PSDM velocity model causes some uncertainties to the seismic image below. Thus, the uncertainties at a target level depend on the complexity of the overburden and the seismic acquisition parameters. At this step a qualitative 3D volume of lateral fault position uncertainties is created.
In the second step the authors focus on a single fault of practical interest. Based on the results of the first step, the authors modify the existing 3D PSDM anisotropic velocity model by introducing additional anomalies that cause maximal changes to the lateral position of the fault on seismic image. Then the authors iteratively re-migrate a small sub-volume around the fault and check the PSDM images and residual moveout. The objective is to find out how far the velocity variations can move the image of the fault and still satisfy available seismic data.
The second step gives more reliable quantitative estimations of the impact of velocity on fault positioning. A real multi-azimuth 3D seismic dataset from the North West Shelf is used to illustrate this sequence.
Complete wavefield seismic structural, stratigraphic, geomorphic and elastic interpretation in the offshore Browse Basin
Authors: Long Andrew , Rajeswaran Dushyan , Greenhalgh Jennifer , Reiser Cyrille , Chemingui Nizar
Published: August 2017

The first quantitative interpretation project in the Browse Basin that used complete wavefields from dual-sensor streamer data to characterise a variety of overburden and reservoir seismic structural, sedimentary and geomorphic features is discussed in this extended abstract.
Having established that complete wavefield pre-stack angle data are amplitude versus angle (AVA) compliant, the authors analyse the elastic response from thin gas sands in a location where well control predicts a weak gas response in terms of the Vp/Vs ratio and negligible response in terms of the acoustic impedance.
Various seismic expressions in the near-surface are better resolved using complete wavefield imaging, including deltaic deposits, potentially prospective patch reefs and intersecting channel systems, and shallow hazards associated with historic drilling failures appear to be resolvable with greater confidence.
On the larger scale, the overall data interpretability is substantially enhanced in texture and character by broadband imaging of primary reflections, and then by subsequent reservoir characterisation.
Initial (deeper) interpretation focused around mapping of the prospective Early Jurassic Plover Formation and the Early Cretaceous Upper Vulcan Formation, in which evidence of channelisation can be demonstrated on conventional migration volumes and reinforced using complete wavefield migration. Ultra-low frequency signal penetration to the deeper Triassic level has been limited historically, but the first complete seismic wavefield data analysis presented demonstrates that a combination of volume attributes provide substantially improved geologic information from the seafloor to the deepest targets.
Collaborative approach: a foundation for successful decommissioning
Authors: Lees Nigel , van Es Willem
Published: August 2017

The industrial capability to decommission assets is in its formative stages, with knowledge and experience limited to a few organisations. Many see this intellectual property as a competitive advantage, underpinning an entrepreneurial approach to secure a share of the projected future spends. While success is usually measured by performance and profit, Wood Group has adopted a broader perspective. Choosing, along with others, to collaborate and actively share lessons, knowledge, and experience for the benefit of the industry and government. Any future strategy for decommissioning developed from the foundation of shared tools and guidance documents will maximise economic recovery for society.
The author outlines the journey so far, identifying the key drivers for collaboration to date, and set out a vision for the next stages. They advocate a truly collaborative approach that shares knowledge between the basins the industry operates in, thus allowing operators to maximise recovery and discharge their license obligations through a cost-effective approach to decommissioning.
The petroleum prospectivity of the Oobagooma Sub-basin and adjacent Leveque Platform, North West Shelf, Australia
Authors: Harrison Paul , Swarbrick Chris , Winterhalder Jim , Ballesteros Mark
Published: August 2017

The Oobagooma Sub-basin of the Roebuck Basin includes the offshore extension of the onshore Fitzroy Trough of the Canning Basin. Together with the Leveque Platform, it covers an area of approximately 50,000 km2, yet only 14 exploration wells have been drilled in the area to date, five of which were drilled in the past 30 years. The sub-basin contains sediments ranging in age from Ordovician to Recent.
This study examines the petroleum prospectivity of a region that is one of the least explored on Australia’s North West Shelf. Recent exploration drilling has revived interest in the area, with the 2014 Phoenix South–1 oil discovery in the offshore Bedout Sub-basin and the 2015 Ungani Far West–1 oil discovery in the onshore Fitzroy Trough.
The two most significant source rock sequences relevant to the Oobagooma Sub-basin are the Carboniferous Laurel Formation and the Jurassic section. The former interval is part of a proven petroleum system onshore and is the source of the gas discovered at Yulleroo and oil at Ungani and Ungani Far West. A thick Jurassic trough to the north of the Oobagooma Sub-basin is believed to be the source of the oil and gas in Arquebus–1A and gas in Psepotus–1.
Hydrocarbon charge modelling indicates significant expulsion occurred during both the Cretaceous and Tertiary from both source intervals. Trap timing is generally favourable given that inversion structures formed in several episodes during the Late Jurassic to Late Tertiary.
The Early Triassic, now proven to be oil prone in the Phoenix South area (Molyneux et al, 2015), provides an additional (albeit less likely) source for the Oobagooma Sub-basin. These rocks are thin to absent within the Oobagooma Sub-basin, so long-distance migration would be required from deep troughs to the west.
Department of Natural Resources and Mines perspective on gas resource development
Authors: Rynne David
Published: August 2017

The Queensland gas sector is undergoing significant transition with emerging opportunities and risks to the state. Australian east coast demand for gas will increase dramatically by 2020, driven primarily by LNG and domestic demand. On the downside, high exploration and development costs and low global oil prices are leading to a scarcity of development capital. Moreover, some domestic consumers remain concerned about gas affordability and availability.
To support the sector and remove barriers to increasing gas supply, the Queensland Government has undertaken extensive analysis and research into the factors that are constraining gas exploration and development—be that geological, technological, gas and pipeline market design, social licence, regulatory, skills, capital, or other. The analysis demonstrates that there are a range of constraints, and that governments at all levels have an important role to play.
This extended abstract summarises the key supply constraints that have been identified in a number of studies recently undertaken by the Department of Natural Resources and Mines.
Training collaboration in Australia
Authors: Lynn Michael , Holmes Veronica
Published: August 2017

It is 2020 and the Australian oil and gas industry has experienced unprecedented growth. The transition to steady-state operations has been hugely successful. Australia is now well and truly on the global map for oil and gas, and is regarded as world class. Trades and technical operators are skilled, experienced, and safely delivering their jobs. The Australian collaborative training model has been successfully in place for three years, and operators and contractors are satisfied with its impact. But how did the industry successfully make this happen?
Looking back to 2015, there were a number of ad hoc collaborative strategies in place to provide oil and gas related skills in Australia. The economic environment at that time, however, necessitated a new look at the collaborative mechanism for reducing operating costs and realising greater efficiencies on workforce development related activities.
In 2015, the Resources Industry Training Council (a joint venture between APPEA and CME) identified workforce development collaboration opportunities, and to articulate the value that could be realised from these opportunities. This project sparked a successful Australian collaborative model for workforce development.
A unique FutureNow visioning presentation will be used to bring to life a world in 2020 where workforce development collaboration is intrinsic to Australian operators’ DNA, and why and how it stuck this time round. The value will be clearly identified in terms cost optimisation, building an industry culture of trust, and how this was used as a springboard for other successful collaborative opportunities.
FutureNow is a fictional representation of the Australian oil and gas industry in 2020, using storytelling to explain a possible journey and outcome for the operators, service providers, workforce, and training bodies.
Northern Houtman Sub-basin prospectivity—preliminary results
Authors: Borissova Irina , Southby Chris , Bernardel George , Totterdell Jennifer , Morris Robbie , Owens Ryan
Published: August 2017

In 2014–15 Geoscience Australia acquired 3,300 km of deep 2D seismic data over the northern part of the Houtman Sub-basin (Perth Basin). Prior to this survey, this area had a very sparse coverage of 2D seismic data with 50–70 km line spacing in the north and an industry grid with 20 km line spacing in the south.
Initial interpretation of the available data has shown that the structural style, major sequences, and potential source rocks in this area are similar to those in the southern Houtman and Abrolhos sub-basins. The major difference between these depocentres, however, is in the volume and distribution of volcanic and intrusive igneous rocks. The northern part of the Houtman Sub-basin is adjacent to the Wallaby Plateau Large Igneous Province (LIP). The Wallaby Plateau and the Wallaby Saddle, which borders the western flank of the Houtman Sub-basin, had active volcanism from the Valanginian to at least the end of the Barremian. Volcanic successions significantly reduce the quality of seismic imaging at depth, making it difficult to ascertain the underlying thickness, geometry and structure of the sedimentary basin. The new 2D seismic dataset across the northern Houtman Sub-basin provides an opportunity for improved mapping of the structure and stratigraphy of the pre-breakup succession, assessment of petroleum prospectivity, and examination of the role of volcanism in the thermal history of this frontier basin.
The rebirth of Papua New Guinea
Authors: Warburton John , Wulff Keiran
Published: August 2017

Gas was first discovered by drilling activity in Papua New Guinea in 1956. Nevertheless it was almost 60 years later when the Exxon-operated PNG LNG Project became the first large-scale commercialisation of the country’s prolific gas resources, with export of the first LNG shipment in May 2014. The proven fluvial-deltaic Late Jurassic, early Cretaceous and Tertiary carbonate reservoirs are prolific petroleum producers. When combined with the high-quality liquid-rich nature of the gas and the onshore location, this has resulted in PNG’s LNG projects being some of the lowest cost and most profitable LNG projects globally. The success of the PNG LNG Project along with the substantial identified existing and yet-to-find gas resources has resulted in a recent resurgence of exploration interest in PNG as companies look to expand and capitalise on the country’s developing position as a globally significant LNG supplier.
In 2015 Oil Search undertook a whole of country review using its extensive database and in-country knowledge. This study incorporated all well, seismic, surface, remote sensing, production and development data, and has resulted in a detailed understanding of the play distribution and risk ranking, and importantly delineated a number of potentially material new play types in the country.
Approximately 4.8 billion barrels of oil equivalent recoverable resources (2P and 2C) have been discovered in PNG to date, of which approximately 85% is gas. The countrywide regional study and common risk segment analysis by Oil Search (2015) established that PNG potentially contains an additional seven billion barrels of oil equivalent resource still to be discovered. The majority of this volume is expected to be gas, estimated to be in the order of 40 trillion cubic feet and 550 million barrels of undiscovered prospective resources.
Oil Search has been active in all of PNG’s known petroleum basins since 1929 and built a substantial database. Pool-size distributions and a countrywide prospects and leads inventory suggest discovery of new giant fields is likely and of sufficient scale to support future LNG projects.
Six sub-basins contain proven petroleum plays that are predicted to extend into under-explored areas. These areas represent the future petroleum exploration frontier in PNG.
Cost transparency: which levers do you pull when we cannot trust the dials? The continued challenge of understanding what is really driving costs
Authors: Smith Jonathan
Published: August 2017

In the past few years an industry-wide race towards achieving construction milestones took place, which drove behaviours of increased spending. Now the focus is on implementing low-cost operating models to optimise the move towards operations in a lower-priced oil world.
KPMG’s recent work and research demonstrates that cost transparency is still a major issue in the upstream oil and gas industry for operators and non-operators. It is clear that it will be difficult to drive out costs and move to the lower cost baselines without significantly improving cost transparency in oil and gas organisations.
In KPMG’s research, operators in Australia and the Association of Southeast Asian Nations (ASEAN) were asked about what challenges they saw, and how they were managing cost in the context of cost transparency.
The focus of the research covered the following areas:

how can you optimise costs if you don’t have transparency?
defining the problem and its boundaries;
external influences;
internal influences and reactions;
the increased scrutiny from joint venture partners;
the challenge to developing a cost culture; and,
the barriers and enablers.

Also, the oil and gas industry has invested heavily in a safety first culture. It has made enormous improvements and the culture is permanent. It could be argued that if the industry put a fraction of the same energy in to building a cost conscious culture then it will weather the lower oil price world so much better.
Continuous improvement in the gas plant
Authors: Ruiz Jose , Jordan Chris
Published: August 2017

Operators that are highly reliable, productive and capable create a culture focused on safety, quality and efficiency. They promote a mindset of continually improving plant performance and reducing system stoppages and failures. Continuous improvement is the key management and work-practice method used to change attitudes and embed this culture in the operating organisation.
In this extended abstract the authors provide an overview of continuous improvement in industry and how they have been successfully applied in one of Australia’s largest gas plants. How continuous improvement allows leaders to set clear expectations for operations, to define plans and aspirations, and to build capability—moving the plant and the organisation to new levels of performance—will be shown.
The extended abstract will demonstrate how continuous improvement creates a culture where people share successes and behaviours across the gas value chain, as well as learning from mistakes. A first-hand account of how continuous improvement has delivered sustained operational improvement in one of Australia’s largest gas plants will also be featured.
Creating the circular advantage for the oil and gas industry
Authors: Coldrick Christopher , Fenn Rowan , Sahota David
Published: August 2017

Maintenance, repair and operating (MRO) materials typically represent 15–20% of the operating costs for a mature oil and gas asset. Of this, a substantial proportion is comprised of high-value repairable equipment such as motors, compressors and pumps. This equipment is often at bottlenecks in the production process and so the impact of materials cost on profitability is magnified by the production ramifications of an outage. Effective management of this equipment is key to the sustainable, profitable operation of any oil and gas asset, and is key to improving the competitiveness of the Australian industry.
Oil and gas companies are adopting a variety of models to handle the repair process, with varying degrees of success. Challenges include:

poor materials availability and lack of traceability;
complex infield materials management processes resulting in costly wastages;
difficulty in managing consistency, suitability and specifications of repairs;
high cost for those undertaking the repairs; and,
correct allocation of responsibility and risk in the materials management process.

Developed in collaboration with Australian oil and gas operators, with input from case studies outside the oil and gas industry, this extended abstract discusses the roles and opportunities for the circular economy in helping companies to meet their sustainability and profitability targets. Using several real-life examples, it makes recommendations for vendors, service providers and operators that can have material impact on the profitability of the industry.
Lower oil and gas prices and the changing LNG landscape
Authors: Graham Chris , McManus Andrew
Published: August 2017

The recent uptick in oil prices from multi-year lows reflects growing anticipation of a tightening of supply and demand fundamentals in global oil markets. Price recovery is expected to come through most notably in the second half of 2016, as the extended period of low oil prices takes its toll on global oil supply growth, and oil demand growth holds up as prices recover.
Rising oil prices will eventually flow through to higher realised LNG revenues in Australasia's long-term oil-linked term contracts. This would provide welcome respite to project economics, many of which have been hit hard by cost escalation and schedule overruns throughout the build phase, and compounded by the collapse in oil price just as these were starting up.
But even with a more favourable oil price environment, the outlook for LNG prices remains weak in the medium term. Lower Asian LNG demand growth and an impending wave of new LNG supply raises the potential for an over-supplied market. With spot prices low, Asian LNG contracts may come under pressure from over-contracted customers. Demands for volume rescheduling and price reductions could become more common.
With demand growth less than anticipated, and faced by competition from new entrants, buyers could look to place excess LNG into the international market. They risk competing for market with sellers, trying to secure customers for their own LNG while cutting costs through optimisation. These changes are forcing all companies to consider the benefits of a portfolio approach to their business. These dynamics, in light of low commodity prices, and the implications for the industry are considered in this extended abstract.
Australian LNG: the cost myths and truths
Authors: Wilkes Martin
Published: August 2017

In recent years the media has published articles relating to the high cost of doing business in Australia. The impacts of low productivity, high-labour costs, and poor performance have all been highlighted as ailments with Australia and within the LNG (construction) industry in particular. This has led to views that Australia is a high-cost environment and Australian LNG is expensive. The numbers that are often quoted appear to support these views, however they overlook—and sometimes mask—aspects of individual projects that are important to understand before making any generic pronouncements about the competitiveness of the Australian industry in general.
This extended abstract:

Exposes the inadequacies of the general comparisons that have been made in the recent past.
Demonstrates the actual impact of several identified issues.
Demonstrates the importance of decisions made early in the project development cycle by respective owners on the projects and project costs.
Identifies the differences and similarities in development and costs of LNG projects in Australia compared to other areas of the world, in particular the US.
Examines the impact of lack of collaboration.
The dawn of LNG price reviews in Asia Pacific
Authors: van Geuns Edward
Published: August 2017

LNG is often sold under long-term contracts with strong volume commitments from both sides, and a cost linked to the oil price. In volatile commodity markets, parties are under pressure to try to review the price under the agreement, either on the basis of price review clauses, hardship clauses, or by relying on general legal principles. This leads to great commercial and legal challenges for both buyers and sellers.
The experience in Europe with gas price reviews can be a source of knowledge for companies on how to deal with price reviews. Long-term gas contracts in Europe also used to be linked to oil prices. This led to a great number of price reviews when oil prices started to soar as of 2005. After that, a new wave of price reviews arose when gas prices decoupled from oil prices in 2009. European gas companies are still dealing with the resolution of those reviews.
On the basis of a number of case studies, this extended abstract sets out the key points that have been learned from a decade of price reviews in Europe with a focuses on practical advice for commercial and legal decision makers. It discusses how negotiations on price reviews are best approached; whether parties should voluntarily disclose confidential information about prices (also in view of competition law), and how arbitrators deal with a gas price review.
Cooper Basin source rock atlas
Authors: Hall Lisa , Palu Tehani , Boreham Chris , Edwards Dianne , Hill Tony , Troup Alison , Henson Paul
Published: August 2017

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin.
The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals.
The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.