bluuebunny/crossref_metadata_2025 huggingface dataset:
A time for tie-ins: the possibility for infrastructure sharing and infrastructure access in Australia's LNG sector
Authors: Pope Clare
Published: August 2017

The development of LNG project infrastructure for exclusive use in relation to LNG projects in Australia has placed an enormous strain on and demand on human and manufactured resources. It has undoubtedly contributed to project delay and cost blow outs, and these have had an effect, along with the falling price of oil and LNG, of putting in jeopardy the development of further LNG projects in Australia.
Tie-ins and joint development may be one way to de-risk and enhance the economic viability of developing future oil and gas resources through the following means:

reducing project delays by using existing developed facilities without the need for extensive pre-FEED and FEED work;
reducing the number of government approvals required by using existing facilities that already have relevant government approvals;
reducing the unit cost of production by using underused facilities or expanding existing facilities at a marginal additional cost to cater for the additional demand and use; and,
reducing exposure to workforce related issues, which have adversely affected the LNG projects in Australia, including unionised workforces, skill shortages and occupational health and safety risks.

There are some key issues however, that need to be considered before embracing this approach, which includes:

Capacity—the availability of capacity in existing infrastructure which is constructed with an individual project in mind will need to be assessed.
Distance—the geographical location of projects can be prohibitive, unlike in other jurisdictions such as the UK North Sea.
Loss of control—operators and the majority of participants may no longer be able to dictate development programs and project schedules.
Pre-FID work—the access agreements need to be finalised and agreed pre-FID and will need to be front-ended at a time when not all issues are foreseeable.
Tolling price—the price needs to be reasonable, yet reflective of the risk taken by the asset owner in allowing third party access and relinquishing some control.

The author will explore these considerations and how some of these issues can be addressed in legal matters, as well as the way other jurisdictions have sought to use infrastructure sharing arrangements and the different ways government has influenced infrastructure sharing.
Intellectual property in the petroleum production and exploration sector—the other hidden asset
Authors: O'Callaghan Tim
Published: August 2017

According to IBISWorld (2013), 7.7% of Australia’s A$11 trillion assets are natural resources and 5.4% is intellectual property. Despite this intellectual property is overlooked as a valuable asset in the oil and gas industry.
As the means of extraction become more complex, the methods and tools needed for the purpose can give one company an edge over another. Intellectual property rights help to protect that competitive advantage.
Companies need to have a strategy for the early identification, management and protection of this asset. Customers, contractors and joint venture partners can create intellectual property ownership issues that must also be identified and properly managed.
This extended abstract provides:
a framework for establishing a robust intellectual property management strategy for companies in the exploration and production sector;
identification of key intellectual property assets of businesses in the sector;
a review of industry specific challenges, such as the requirement under WA’s Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 to disclose trade secrets and commercially sensitive material about downhole substances; and,
consideration of model agreements used in the sector, such as the AMPLA Model Petroleum Exploration Joint Operating Agreement.
Managing climate change adaptation in oil and gas production
Authors: Beeke Paul van der
Published: August 2017

Oil and gas production operations occur in widely diverse onshore and offshore contexts. The global industry has a long history of coping with climate variability, extreme climatic conditions and extreme weather events. Climate change, however, is projected to take the new climate beyond the range of historical variability in many places where oil and gas production facilities are located.
Oil and gas infrastructure often has an expected operational life of 50 years or more, which would take new operations to 2064 and beyond. This is well inside the timeframe predicted for substantial climate change with consequent risks to longer term operational continuity and supply chain security.
In recent years, the realities of climate change beyond pre-industrial age historical variability, and the associated business risks, have become accepted by the major global oil and gas industry players. Other stakeholders, including corporate, institutional and private investors and corporate regulators, are also becoming more assertive in their demands for corporate disclosure of climate change risks, adaptation management plans and evidence of effective implementation of adaptive measures.
Industry decision-makers need scientifically sound and robust data applied to their specific operations and business conditions to support business case-based investment decisions for new project feasibility, capital and operational expenditure, and the management of long-term strategic liabilities.
This extended abstract provides an overview of the complex and interconnected web of climate change effects that should be considered. It also outlines approaches that could be employed to manage the risks and meet stakeholder expectations.
Workplace productivity: challenges and opportunities in oil and gas
Authors: Gardner Chris
Published: August 2017

This extended abstract complements APPEA’s Improving Labour Productivity Report, while serving as a bridge for the submission that APPEA made to the Productivity Commission as a part of its intended review into workplace regulations. This extended abstract highlights some of the challenges faced in the oil and gas construction and operations sector, examining some of the underlying regulatory drivers. The international context will be drawn upon, together with an examination of possible solutions.
Browse Basin petroleum accumulations
Authors: Kuske Tehani , Poidevin Steven le , Edwards Dianne
Published: August 2017

The Browse Basin lies offshore from WA’s Kimberley region and hosts vast accumulations of natural gas, some are rich in condensate, making it Australia’s next major gas producing province on the North West Shelf.
It is estimated that the Ichthys gas accumulation contains 12.8 trillion cubic feet (Tcf) of gas and 527 million BBL of condensate, and represents the largest hydrocarbon accumulation with recoverable liquids found in Australia since the discovery of the Gippsland Basin and Barrow Island oil fields in the 1960s.
Similar amounts of gas, albeit drier (CGR 20–30 BBL/MMscf) are hosted within the Brecknock, Calliance and Torosa accumulations (cumulative of 15.9 Tcf gas and 436 million BBL condensate). For this reason, the Browse Basin continues to be a focus of exploration, in which both international companies and Australian explorers are capitalising on LNG opportunities.
This extended abstract provides a summary of hydrocarbon accumulations encountered in the Browse Basin (up until late 2014). Accumulations discovered in the Browse Basin include: Abalone, Adele, Argus, Bassett, Torosa, Brecknock and Calliance, Ichthys, Concerto, Mimia, Burnside, Caspar, Caswell, Columba, Cornea, Focus, Sparkle, Crux (including Libra), Hippolyte, Echuca Shoals, Gwydion, Marabou, Poseidon (including Kronos, Boreas, Zephyros and Poseidon North), Crown (including Proteus and Pharos), Psepotus and Lasseter.
The authors provide a summary of the regional geology, evolution and tectonic development of the basin, and discuss the hydrocarbon reserves and hydrocarbon potential of the basin. This provides a guide to assist potential future exploration programs in the Browse Basin.
Improved imaging of the Strzelecki Formation by the reprocessing of 3D seismic reflection data: onshore Gippsland Basin, Australia
Authors: Nourollah Hadi , Aliemrani Javad
Published: August 2017

The Wombat 3D seismic survey was recorded by Lakes Oil in 2008 following the drilling of the Wombat–3 well. The survey was aimed at identifying the structures better inside the Strzelecki Formation and the underlying Rintoul Creek Sandstone, and to give a better understanding of the provenance of the gas encountered in the first three Wombat wells and the oil encountered at depth in the Wombat–3 well.
Seismic acquisition design and processing in this area are challenged by the presence of coal measures in the Latrobe Group, which overlies the zone of interest, absorbs most of the incident seismic energy and complicates seismic imaging through the generation of multiple reflection events.
A novel approach, described as multi-line decomposition, modelling and synthesis, was developed to model critical imaging parameters and in particular the velocity model for midpoint stacking and migration. This approach is demonstrated through the reprocessing of the Wombat 3D seismic survey and is compared with a conventional 3D processing approach and original survey processing examples.
The reprocessed seismic section provides a significantly improved image of the deeper structures, delineating a number of continuous reflectors in the Early Cretaceous formations. It also provides the opportunity to build a more accurate model of the basement.
Pore scale imaging and modelling of coal properties
Authors: Ramandi Hamed Lamei , Mostaghimi Peyman , Armstrong Ryan T. , Arns Christoph H. , Saadatfar Mohammad , Sok Rob M. , Pinczewski Val , Knackstedt Mark A.
Published: August 2017

A key parameter in determining the productivity and commercial success of coal seam gas wells is the permeability of individual seams. Laboratory testing of core plugs is commonly used as an indicator of potential seam permeability. The highly heterogeneous and stress-dependent nature of coal makes laboratory measurements difficult to perform and the results difficult to interpret.
Consequently, permeability in coal is poorly understood. The permeability of coal at the core scale depends on the geometry, topology, connectivity, mineralisation and spatial distribution of the cleat system, and a better understanding of coal permeability, that and the factors that control this depends on having a better understanding and detailed characterisation of the system.
The authors used high resolution micro-focus X-ray computed tomography and 2D-3D image registration techniques to overlay tomograms of the same core plug, with and without X-ray attenuating fluids present in the pore space, with 2D scanning electron microscope images to produce detailed 3D visualisations of the geometry and topology of the cleat systems in the coal plugs. Novel filtering algorithms were used to produce segmentations that preserve cleat aperture dimensions and together with large-scale fluid flow simulations, they performed directly on the images and were used to compute porosities and permeabilities.
Image resolution and segmentation sensitivity studies are also described, which show that the core scale permeability is controlled by a small number of well-connected percolating cleats. The results of this study demonstrate the potential of simple image-based analysis techniques to provide rapid estimates of core plug permeabilities.
Remote monitoring of well site biostratigraphy
Authors: Gard Gunilla , Crux Jason , Lee Bernard , Belgarde Catherine
Published: August 2017

Real-time well site biostratigraphy monitors the stratigraphic progress of drilling wells and can show if the well is conforming or deviating from predicted stratigraphy; it can also show whether total depth criteria have been met.
New technology implemented by BHP Billiton Petroleum on wells in the Gulf of Mexico make it possible to undertake well site biostratigraphy remotely. An automated microscope has been developed that can scan and photograph nannofossil slides at a quality almost indistinguishable from conventional microscopy. A technician present at the well makes a slide from ditch cuttings and places it on the microscope, where software scans the slide at several focus levels, compresses the files and transfers the images to the office. A biostratigrapher in the office looks at the images and makes taxonomic identifications.
When implemented on the first well, the technology provided immediate results by being the first data acquisition process to recognise that a section was faulted out. Remote well site biostratigraphy also creates a verifiable record, making it possible to quality-control biostratigraphic interpretations; it also frees up space on the rig and improves health and safety for biostratigraphers. Delays in file transfers from the rig to the office are being addressed by reducing the size of the image files by discriminating the fossils from the background.
Flow assurance application to unconventional gas wells: down-hole separation efficiency calculations with computational fluid dynamics
Authors: Leahy Martin , Holbeach James
Published: August 2017

Coal bed methane (CBM) operations reduce the reservoir pressure to desorb gas from the coal matrix. Internationally, this is often achieved by drawing down water through pumping from the reservoir, by surface or down-hole pump. Pumping water lowers the bottom-hole pressure and also provides a first pass separation of water and gas in the well annulus.
Set-point pressure pumps are typically used to pump water up the inner tubing, whilst gas is produced in the outer annulus. In many operating CBM applications this separation is adequate, removing a large percentage of bulk and droplet-based water from gas, negating the need for secondary surface separation. Key to this separation is the ability of the water to drain downwards to the bottom of the well without being carried over with the upwards moving gas.
This is a counter-current flow regime with large superficial gas velocities (as high as 30 m/s) and small superficial liquid velocities (less than 1 m/s). The annular/droplet regime is prevalent and there is potential for droplet carry-over with gas, affecting the need for further separation. Computational fluid dynamics (CFD) was used to model the process of gas and water separation down hole in the perforation zone to calculate the fate of water droplets as they pass downwards counter-current to upwards moving gas. A flow envelope was developed to calculate the carry-over liquid flow rate for a range of gas flow rates. This work assists the design requirement for wellhead surface separation or otherwise for Australian CBM applications.
Learning from lessons in downhole gauges as part of a well optimisation strategy
Authors: Kaya Remzi , McCowan Brandon , Kaya Melodi
Published: August 2017

Downhole gauges are designed to operate in a harsh working environment and are commonly installed in conjunction with a progressing cavity (PC) pump. They measure the pressure at or slightly above the PC pump and, along with a casing pressure gauge, they can be used to measure the fluid level in the well.
An understanding of the fluid level in a well allows the operator to control the well drawdown process and protect the PC pump if it is installed with a well optimisation system that can maintain the desired water level or stop the pump if required.
Downhole gauges provide valuable data for reservoir analysis and well planning, especially for low-perm coals. They are often criticised for failing, but root cause analysis often finds that failure is not the gauge, rather it is caused by other components of the well completion.
This extended abstract discusses the operational experience and analysis of operating downhole gauges across a 10-year period while working with several gas companies in Queensland, NSW and China. In these locations different cable-type downhole gauges, such as a low-density polyethylene (LPDE) sheathed, armoured cables and solid tubular stainless steel cables, were fixed to the tubing. This knowledge can extend the working life of downhole gauges and help operators develop well optimisation strategies.
Creating lasting and fulfilling careers for Indigenous Australians
Authors: Williams Llewellyn
Published: August 2017

Recruiting Indigenous Australians is part of the oil and gas industry’s social responsibility. Indigenous recruits need to be ensured that they have lasting and fulfilling careers.
In Transfield Services’ experience, retention is often the greatest challenge and significant time and resources is spent to identify strategies to help Indigenous employees progress their careers positively.
The first and, arguably, the most important element is to engage early with Indigenous communities to identify key local Indigenous stakeholders and establish strong and trusting relationships. This provides a contextual platform and understanding that guides not only the recruitment process and role fit, but also the support required for individuals through their employment.
Indigenous employees then are assigned a mentor to assist in developing their occupational skills. Mentors can be volunteers from across the company but they must work closely with Indigenous development managers to ensure full cultural awareness.
Cultural awareness training should also be carried out extensively across an organisation and be backed up by day-to-day application of human resource polices that accommodate cultural elements specific to Indigenous Australians.
Critically, organisations must also hold themselves accountable. Publicly available Reconciliation Action Plans (RAPs) must set transparent targets for recruitment and retention, and progress must be continually monitored by informed and independent advisory boards.
In 2007, Transfield Services launched its first Indigenous participation strategy. It then became the first service provider to implement a RAP in 2009. Since then, it has launched an updated RAP, which earlier this year was endorsed by Reconciliation Australia—one of only a handful in the country to have this accreditation.
Fraccing forum
Authors: Williamson Maxwell
Published: August 2017

There have been 13 major inquiries completed during the past few years that have addressed the issue of hydraulic fracture stimulation (fraccing) in Australia. There are two inquiries due to report before mid-2016; namely in SA (Natural Resources Committee, Parliament of South Australia, 2015), and the Senate Inquiry (Parliament of Australia, 2015). These inquiries are in addition to many others conducted in overseas jurisdictions including various states of the US, Canada, and in countries in the European Union, including the UK. Concerns are usually concluded around ensuring there is a proper regulatory environment to confirm that the use of fraccing is conducted using international best practices, and the risk to the environment is minimised. In each and every responsible inquiry the conclusion has been that there is no scientific or public policy reason that would justifiably prevent the use of fraccing as a pre-well completion stimulation technique.
This paper attempts to synthesise basic data about fraccing—why the ability to fracture stimulate wells is no longer a luxury but a necessity in deep oil and gas production—to convey factual information and summarise the results of inquiries in Australia to date.
Comparisons between hydraulic fracture stimulation operations and results in the US and Australia are intended to provide comfort that some of the potentially more intense (massive) hydraulic fracture stimulation operations routinely conducted in the US (and Canada) on an individual well basis are not contemplated in the immediate future in Australia. The scale of North American fraccing activities may bear little resemblance to what may be proposed or occur in Australia owing to fundamental differences in geology, basin stress regimes, infrastructure, and cost and logistics, among other factors.
The author’s conclusion is that fraccing in Australia can and will be carried out in a sphere of safety and regulation that many other countries are likely to aspire to copy. It would, however, be foolish to suggest hydraulic fracturing operations are not without some risk, as with many industrial and other daily activities, but the risks can be managed or mitigated with sound engineering and scientific practices. This is irrespective of the messages by opponents of hydraulic fracture stimulation in oil and gas wells. The modern practice of fraccing has been used now for more than 65 years, albeit with increasing scale commensurate with technological advances, which has caught the public’s imagination. Indeed, the results of inquiries have given no credence to demonising the technology.
The use of stable carbon isotope trends as a correlation tool: an example from the Surat Basin, Australia
Authors: Hentschel Astrid , Esterle Joan S. , Golding Sue
Published: August 2017

The Surat Basin’s Middle Jurassic Walloon Subgroup is a productive coal seam gas source in Queensland, Australia. The Walloon Subgroup can be subdivided into the Upper and Lower Juandah coal measures, the Tangalooma Sandstone, the Taroom Coal Measures, and the Eurombah/Durabilla Formation, from top to bottom.
Correlation across the basin is challenging due to high lateral variability and lack of extensive stratigraphic markers. The Walloon Subgroup is also, in places, incised by the overlying Springbok Sandstone, sometimes interpreted as far down as the Tangalooma Sandstone.
New age dates suggest that the Walloon Coal Measures are Oxfordian in age and mark a period of high rates of Corg production and burial, and an intermittent decrease of atmospheric pCO2. The un- or dis-conformable base of the Springbok Sandstone coincides with a turning point of this supposedly global phenomenon.
This study uses organic stable carbon isotope trends as a correlation tool within the Surat Basin’s Walloon Subgroup and its overlying Springbok Sandstone. Analysis of a stratigraphic suite of coal samples from several wells across the Surat Basin shows a gradual enrichment in 13C up section from the Taroom to the Lower Juandah Coal Measures, with the most positive δ13C values within the Upper Juandah Coal Measures. Thereafter there is a rapid reversal to more negative δ13C values for coal samples of the Springbok Sandstone. The upward enrichment occurs well before the shift in maceral composition to increased inertinite content in the coals, suggesting more global allogenic processes are controlling the carbon isotopic trend. The consistency of these trends lends a more confident correlation for sub-units within the Walloon Subgroup, and assists in determining the level of incision disconformity of the Springbok Sandstone.
A Cooper Basin simulation study of flow-back after hydraulic fracturing in tight gas wells
Authors: Sarkar Sume , Haghighi Manouchehr , Sayyafzadeh Mohammad , Cooke Dennis , Pokalai Kunakorn , Mohamed Ali Sahib Fathima
Published: August 2017

After fluid injection (slickwater) during hydraulic fracturing, the flow-back of fracture fluid is necessary before gas production starts. A review of fracture treatments indicates that the incomplete return of treating fluids is a reason for the failure of hydraulic fracturing and is associated with poor gas production. The aim of this study is to investigate the parameters that limit flow-back in low permeability gas wells in the Cooper Basin.
The authors used numerical simulation to find the critical controlling parameters to introduce the best practice for maximising the flow-back in the Cooper Basin. Several 3D and multiphase flow simulation models were constructed for three wells in the Patchawarra Formation during fracture fluid injection, soaking time and during flow-back. All models were validated using history matching with the production data.
The results show that the drainage pattern is distinctly different in the following directions: vertically upward, vertically downward, and horizontal along the fracture half-length and along the matrix. The lowest recovery is observed during the upward vertical displacements due to poor sweep efficiency. Furthermore, it is observed that drawdown does not influence the recovery significantly for upward displacements. Surface tension reduction, however, can improve sweep efficiency and improve recovery considerably. Also, the wettability of the rocks has a significant impact on ultimate recovery when the effect of gravity is dominant. The authors conclude that a significant amount of injected fluid is trapped in the formation because of poor sweep efficiency and formation of gas fingers, which results from low mobility ratio and gravity segregation.
Advances in the simulation of offshore heavy lifts from experiences in Bass Strait, Victoria
Authors: Wales Stuart , Swaik Glenn , Ting Kee Yik , Jayasinghe Kanishka , Gumley Jon , Potts Andrew
Published: August 2017

There has always been a clear need to demonstrate that project critical offshore heavy lifts can be conducted safely, within allowable criteria, for the metocean conditions likely to occur in-field.
Extensive guidance is available in the design codes for lifts subsea but, for lifts in air, dynamic analysis of the response of a suspended mass is not fully addressed. Analyses generally yield results that do not agree well with operating experience and cannot easily be assessed against the limited code guidance available. Traditionally, operator skill and experience has thus been relied on to justify the operability of such lifts. Recent experience in engineering the lift of a 500 tonne module onto the Yolla Platform in Bass Strait, Victoria, has further underlined the deficiencies in analytical techniques and approaches available to the industry.
This paper presents experience gained from the pre- and post-lift analysis of an instrumented lift operation recently conducted by the mono-hull vessel Sapura 3000 in the challenging environmental conditions of Bass Strait. This analysis was used to demonstrate that the lift could be conducted safely within tight operational constraints, meeting the codified criteria set.
Subsequent analysis of data gathered during the lift was used to explore and refine modelling assumptions to aid the engineering of future challenging heavy lifts. The analyses conducted advanced state-of-the-art work in this field for the offshore industry.
By enabling numerical techniques for heavy lifts, which are typical of many other offshore operations, safety will be improved, project contingencies can be properly estimated through more accurate prediction of downtime, and cost savings can be achieved by the selection of more effective vessels for the task.
Analytical investigation of well/perforation scale effect on sand production of weakly consolidated sandstones
Authors: Tehrani Soroush , Sarmadivaleh Mohammad , Sinaki Ahmadreza Younessi , Mostofi Masood , Bayati Massoud
Published: August 2017

Investigating the risk of sand production is a common practice for developing unconsolidated and weakly consolidated reservoirs, particularly with designing the completion system of development wells. The risk of sanding may be different for open hole and cased and perforated completion systems. Part of this difference is a result of the different size of the boreholes—that is, open hole versus perforation tunnels— which is known as borehole scale effect. The amount of research dedicated to investigate the borehole scale effect on sand production is very limited. Research has been carried out by conducting thick-walled cylinder (TWC) tests on samples with different inner to outer diameter ratios. The impacts of sample size and boundaries on the induced stresses around the borehole and failure were, however, not differentiated from the borehole scale effect.
In this paper, a comprehensive analytical approach is performed to investigate the effect of the size of the sample and boundaries on TWC tests and borehole failure. To do this, four different failure criteria—Mohr-Coulomb, Drucker-Prager, Mogi and modified Lade—are compared with previously published experimental results.
The analysis shows that the size of the sample and the boundaries may significantly change the TWC strength of the rock. The TWC changes by different inner to outer diameter ratios, however, may not be fully justified by the analytical approach. Hence, a scale effect factor must be introduced to replicate the experimental results.
Changes in labour and safety regulation offshore: the productivity implications
Authors: Taylor Eleanor
Published: August 2017

In recent years there have been ongoing tussles regarding the regulation of employment in the offshore oil and gas industry. Much of this conflict relates to the extent of union involvement in the industry, and the impact increased union activity may have on cost and productivity. This conflict has played out in the courts, legislature and the media.
It is evidenced in the debate over the application of Australian migration laws to foreign workers offshore. This has involved lobbying by a number of organisations and Federal and High Court challenges to parliamentary intervention. Whether these laws apply has important implications for industry, as they include the practicalities and cost of engaging adequately skilled contractors for specialist tasks on major projects.
Another recent example is the Australian Council of Trade Unions (ACTU) advocating for the application of the harmonised workplace health and safety regulations to the offshore industry. The application of these regulations would likely affect the extent of union involvement in the workplace, and have consequent cost and efficiency implications.
In this extended abstract the author examines the impacts on industry of:

recent and upcoming changes in employment regulation;
uncertainties around the application of employment laws offshore;
proposed changes to safety regulation; and,
areas where industry is seeing advocacy for change.
Safety leadership and collaboration in the Queensland natural gas exploration and production industry
Authors: Simpson Walter , Greene Mark , O'Donnell Sean , Zaunbrecher Michelle , King Warwick , Ciccone Steve
Published: August 2017

The industry in Queensland operates within a common geographical area and uses similar technologies with common hazards and risks. In terms of safety companies must be seen as one industry and not separate entities. As a result, collaboration on safety is a natural outcome, and in 2014 this led to the creation of the Queensland Natural Gas Exploration & Production Industry Safety Forum (known as Safer Together), an inclusive member-led organisation of a range of operating and contract partner companies.
Initial emphasis was on the set-up/organisation and getting early engagement. With more than 80 companies signed up as members in the first 12 months, Safer Together made a strong start.
The emphasis has now switched to delivery, and with all member companies feeling the strain of the industry downturn, working together has never been so crucial to ensure that safety is never compromised.
This extended abstract presents a case study of what Safer Together is learning about the fundamental prerequisites required to ensure long-term sustainability and the success of the forum.
Challenges discussed include:

maintaining and increasing membership in tough times;
ensuring senior leaders continue to be actively engaged, regardless of other business pressures;
ensuring simple solutions don’t become too difficult to implement when rolled out to many different companies;
avoiding initiative overload; and,
demonstrating tangible value to member companies.

This is not an easy journey, and more challenges lie ahead. But the enormous safety benefits make it the right thing to do as an industry.
Access to information in joint ventures: the dangers of being kept in the dark
Authors: Freeman Anne
Published: August 2017

Operators of joint ventures have, by reason of their position, first-hand access to all information relating to the joint venture, including financial results, technical data, and documents relating to relationships with third parties and contractors. Non-operators regularly strike difficulty in obtaining all the information they need in relation to the affairs of joint ventures, especially if a dispute is emerging between participants in it.
This extended abstract explores various mechanisms for non-operators to obtain joint venture records, including express provisions in the joint venture agreement itself, and the potential to argue that there should be a right to obtain records implied into the agreement. Other potential mechanisms will also be canvassed, including the assertion of fiduciary duties owed by the operator that might provide the non-operator with rights to obtain information.
In the 2013 decision of Alliance Craton Explorer v Quasar Resources, the Full Court of the Federal Court considered a joint venture agreement that did not explicitly provide access to the non-operator records of the joint venture. The court refused to imply a term providing access to the records, and dismissed arguments by the non-operator that the operator was its agent and that the non-operator had proprietary rights to the information it sought. This extended abstract discusses the implications of this decision.
Warning. Danger. Caution: over-regulation leads to unsafe work environments
Authors: Fletcher Duncan
Published: August 2017

The oil and gas industry is no stranger to explosions, fatalities and other catastrophic incidents. If, however, these dangers are outside of the normal routine, what is the value of countless occupational health and safety rules, regulations, and a bureaucracy to manage them?
The over-regulation of workplace safety threatens to replace intelligent judgment with rigid policies and procedures. The industry needs to examine which strategies ultimately lead to the best safety outcomes. The personal responsibility of individual employees is critical to genuine engagement in the day-to-day management of workplace safety. Over-regulation can also drive up costs for contractors who are forced to comply with the same inflexible standards and rules. Historically, tensions between employers, employees, and contractors have hindered rather than helped workplace safety.
In the future, employers and management should strive to share the burden of workplace safety through meaningful conversation with the people on the ground floor. The industry should not rely on a new hazard sign, safety briefing, start-up check, emergency switch, hand guard, policy document, or a human resources buzzword. The best safety systems rely on common sense. Beware—the machine has no brain, use your own. The question is, does the regulatory framework allow this to occur?
Measuring organisational resilience: small firms dealing with gas investment cycles
Authors: Ford Jerad , Verreynne Martie-Louise , Steen John
Published: August 2017

The capital construction phase of the CSG–LNG projects in Queensland has required significant investment in employment, and provided opportunities for local contractors with spillover effects for the regional economy. As these projects transition into the operational phase they will sustain a different supply chain profile, which has implications for the local economy.
The authors’ primary question is, how do local business adapt to these changes?
Initial results indicate that some businesses adapt better than others. The authors call these small to medium sized (SME) businesses resilient organisations.
Building on data from a survey of SMEs in the gasfields, the authors show how resilient firms are able to learn, adapt, innovate and renew in response to these environmental changes.
The findings suggest ways to support SMEs to adapt to the changes brought about by this economically important industry. The findings from this study also have wider implications for other regions in Australia and around the world that may encounter significant oil and gas investments in the future.
How does a community add value to the oil and gas industry?
Authors: Trundle Stuart , Probert Anne
Published: August 2017

As pressure mounts for oil and gas companies to demonstrate tangible value to the communities in which they operate, there is a growing imperative for groups to actively engage with the industry and its operators. Regions who partner with the industry to identify and implement initiatives that leverage the investment can see very real economic and social gains from hosting oil and gas exploration and production.
Venture Taranaki, the regional development agency for New Zealand’s only commercially producing oil and gas region, has been part of such a successful partnership in that area.
They have worked extensively in the space between the industry and the community to maximise the benefits to the region. In doing so they have helped position Taranaki as a force in New Zealand’s economy, and it has developed initiatives that demystify and demonstrate the industry’s value to their community stakeholders, extending this momentum across the oil and gas supply chain.
Its commercially neutral services have also advanced collaboration among the companies, fostered collective promotion of their capabilities, and assisted with management of demand-supply challenges in relation to project and shutdown planning.
In this extended abstract the authors give an insight into their experiences, lessons for other regions, and proposals to further advance the industry-community relationship.
Remote ops: a new way of delivering traditional field operations
Authors: Little Michael
Published: August 2017

Santos GLNG is a joint venture that supplies clean energy to global markets. The business produces natural gas from Queensland’s coal seams in the Bowen and Surat basins and converts it to liquefied natural gas (LNG) at its new facility on Curtis Island, near Gladstone, prior to export.
From its inception, Santos GLNG has been committed to minimal impact and maximum efficiency, with safety before all else. Delivering on this commitment, in the context of a vast geographic footprint, required innovation—a new way of delivering traditional field operations. As a result, Santos GLNG successfully developed a high-tech $10 million operations centre that delivers the ability to centrally monitor the production and progress of its assets in the gas fields in real-time, 24 hours a day, seven days a week. Located in Brisbane (more than 450 km away from the gas fields), the centre comprises 90 large screens, one of the world’s largest touch screens, six simultaneous video conferencing facilities, and 30 km of wiring. Key benefits include:

Real-time monitoring of the performance and production of all assets in the field, including compressors, pumps, wells, flow lines, pressure vessels, and pipelines.
Remote start-up or shut-down capacity, which ensures facilities operate to the highest standards of production.
Virtual collaboration and knowledge sharing across multiple sites and assets through the latest teleconference and video conferencing technology.

In 2015, the operations centre successfully took control of a range of newly commissioned assets. Most notably, this included Santos GLNG’s three new major compression hubs, which together at nameplate capacity will be able to process 555 terajoules of gas per day.
Enabling operational excellence through the effective management of master data
Authors: Puzey Mark , Latham Stephen
Published: August 2017

Many organisations in the industry have a constant struggle with managing oil and gas master data effectively to enable operations and maintenance to be carried out efficiently and safely. Poor data quality costs organisations time and money, and increases risks of production downtime. This results in inefficiencies, rework, and sub-optimal decision support.
In this extended abstract, the authors provide insight from their experience into overcoming many years of poor data quality that impact ability to analyse maintenance reliability data that can effectively drive efficiencies and reduce outages caused through breakdowns.
Insights includes insights from a global fact-finding mission, analysing the big data management of large oil and gas and related companies around the world – with valuable lessons in understanding why these types of data projects fail so often. Challenges include finding where and why data quality is in an unreliable state, and additionally, how to allow cleansed and new data to remain clean and effective and promote efficiency. Other challenges include changing organisation behaviour to value data, and providing streamlined processes to sustain data quality.
Maximising value in mega-projects: Ichthys LNG project
Authors: van der Linden Cornelis , Townsend Bill
Published: August 2017

The INPEX-led Ichthys LNG Project is one of the world's most complex gas developments, incorporating all elements of the production chain.
It is three mega projects rolled into one.
The offshore project includes the world’s largest semisubmersible central processing facility and a large floating production, storage and offloading facility.
An 890 km subsea gas export pipeline joins offshore facilities to a state-of-the-art onshore processing plant near Darwin.
Managing more than 30,000 personnel working across the globe to construct this project demands excellence in project management.
INPEX’s approach allows seamless interface management and a tight grip on cost and schedule to deliver a complicated, giant project, and 40 years of future field operations.
Achieving data-driven efficiencies with integrated planning analytics
Authors: Boto Elizeu
Published: August 2017

The logistical challenges of drilling in the Surat and Bowen basins, and the high operational costs allied to an oil price downturn, is forcing the CSG to LNG players in Queensland to reinvent their delivery models.
The concept of a drilling factory has been the holy grail of the oil and gas industry for many years, and many local operators have turned their attention to the lessons learned by the North American shale players. These companies, with virtually no increase in capital costs, were able to improve time to drill, wells per rig and total distance drilled by 50–150% in fewer than five years. This revolution has been achieved not only with the advent of improved drilling technology but also the use of data-driven productivity and automation.
Leveraging the experiences of North American companies, local operators are embracing the use of analytics to boost operational efficiencies and improve the safety of their operations.
APLNG, for example, has used analytics to integrate multiple aspects of planning and operations to optimise field development for future phases of the project. As the volume of wells continues to increase, more supply chain related issues will require mitigation.
Analytics solutions can assist not only in the isolation of wellbore-related non-productive time issues and reduce drilling cycle times for individual wells, but also to use the best tools and techniques in only the best parts of the field.
Implications of LNG exposure on the competitiveness of Australia
Authors: Lambie Ross , Thomas Nicole , Whitelaw David
Published: August 2017

Australia’s eastern gas market has historically been one of low prices and stable, long-term contracts. The development of coal seam gas (CSG) and the construction of Queensland’s three CSG to LNG projects is driving a tripling of gas production in eastern Australia and changes to historical patterns and directions of gas flows throughout the market. This transition from an isolated market to one linked to international LNG markets, coinciding with the unwinding of many legacy contracts, is leading to unprecedented change and will have profound effects on all participants.
This extended abstract considers the implications of LNG exposure on the competitiveness of Australia’s eastern gas market. It will draw on the expertise of the gas market specialists in the Office of the Chief Economist, and the oligopolistic model of the market, to consider impacts on supply, demand, price, and the level of competition in various sectors of the market.
One of the initial findings is that the volatility of global LNG spot prices is likely to have a significant impact on both gas production and demand in east Australia, given the scale of LNG exports relative to the eastern market. The extended abstract explores a range of LNG demand scenarios for the eastern gas market. It will emphasise the fundamental importance of expanded gas production on market outcomes, and the need for ongoing gas exploration and development to support the market through the transition.
Automatic NMO correction in anisotropic media and non-hyperbolic NMO velocity field estimation
Authors: Sedek Mohamed , Gross Lutz
Published: August 2017

The authors propose a new method to automatically normal move-out correct pre-stack seismic reflection data that is sorted by CDP gathers, and to estimate the normal move-out (NMO) velocity (Vnmo) as a full common depth point (CDP) velocity field that instantaneously varies with offsets/azimuths.
The method is based on doing a pre-defined number of NMO velocity iterations using linear vertical interpolation of different NMO velocities at each seismic trace individually. At each iteration the seismic trace is shifted and multiplied by the zero offset trace followed by the summation of the product. Then, after all the iterations are done, the one with the maximum summation value is chosen, which is assumed to be the most suitable NMO velocity trace that accurately flattens seismic reflection events. The other traces follow the same process, and a final velocity field is then extracted.
Another new, simple and fast method is also introduced to estimate the anisotropic effect from the extracted NMO velocity field. The method runs by calculating the spatial variation of the estimated NMO velocities at each arrival time and offset/azimuth, therefore instantaneously estimating the anisotropic effect.
Isotropic and anisotropic synthetic geological models were built based on a ray-tracing algorithm to test the method. A range of synthetic background noise was applied, starting from 10–30%. The method has also been tested on Hess’s model and coal seam gas field data CDP examples. An Alaskan pre-stack seismic CDP field example has also been used.
Core scanner technologies: take everything without breaking
Authors: Rodrigues Sandra , Esterle Joan
Published: August 2017

Modern core scanning technologies, such as hyperspectral CoreScan™ or X-ray fluorescence (XRF) Itrax, which allow data acquisition without the necessity of breaking the core for speciality analysis, are receiving increasing interest in coal and CSG industries in the past few years. Such technologies are able to characterise and evaluate mineral matter in greater detail than conventional sampling and analyses, producing mineral maps and mineral/elemental profiles throughout the core.
Although mineralogical information is the main output from both techniques, CoreScan™ has the ability of producing organic profiles that allow the recognition of the different lithotypes in the coal based on the spectral reflectance as well as rank, which makes a potential technique for coal quality. On the other hand, XRF Itrax core scanner allies the chemical elemental profile, from major to trace elements, with an X-radiographic image, creating a dynamic duo between stony partings and coal, and within the coal between bright and dull lithotypes, through contrasting image properties. These emerging technologies will allow coal reservoirs to be analysed quickly and reliably without subsampling that could introduce bias from the user.