bluuebunny/crossref_metadata_2025 huggingface dataset:
Innovative structural engineering and execution approach to delivering modular facilities for the Gorgon Project
Authors: Dev Partha , Shah Parag
Published: August 2017

The Gorgon Project on Barrow Island, located about 60 km from the northwest coast of Australia, was given the green light in September 2009. Construction and commissioning of the Gorgon LNG trains is limited to a 300 hectare development on a Class A reserve. Our commitment to the environment has driven our use of extensive modularisation to build the LNG trains. All of the major components have been pre-fabricated and assembled offsite into transportable parts,“ significantly reducing our footprint on the island. Subsequently the structural modules (including pre-assembled Piperacks) have undertaken a journey on a scale and complexity unmatched in the global LNG industry. The modules have been designed and built at diversely located engineering, fabrication and construction sites. These are then loaded out and sea transported from different international shipyards in more than 6. sea-transportation voyages, carrying more than 300 modules weighing more than 280,000 tonnes under constantly varying and hostile sea-faring conditions. The modules reach their final destination at Barrow Island to be installed without impacting the island’s uniquely treasured flora and fauna. These modules are designed to operate for its entire service life on cyclone-rated Barrow Island, which in the past has registered the highest ever wind gust of 408 kmph. Design and execution of the modules to sustain severe environmental conditions during its service lifecycle has been made possible by employing an innovative engineering mindset supported by robust structural methodologies to develop suitable facilities that can operate in a highly complex environment. This extended abstract showcases the structural engineering and execution methodologies that successfully overcame the challenging journey of the modules, thereby delivering a world class development co-existing with conservation in a pristine nature reserve on a very limited footprint.
Maximising safety and environmental performance during onshore seismic acquisition using cable-less technology
Authors: Shaw Jamie , Silverman Matt , Dunn Geoff , O'Mara Katrina
Published: August 2017

Recent advances in the acquisition of onshore seismic data without cables have greatly reduced impacts on environmental and heritage values and increased recording efficiency. Onshore oil and gas exploration has expanded significantly across Australia. As a result, the need to gather quality data while reducing the environmental, social, and safety impacts of the activities has driven innovation in exploration technologies. In WA, exploration permits are granted for areas that include privately held farm land, pastoral leases or unallocated crown land. This can result in tensions between exploration companies, their contractors, and land holders. Cable-less seismic data acquisition systems provide significant opportunities to reduce the environmental, community, and safety impacts. Cable-less systems typically require significantly fewer trips along the acquisition line, considerably reducing the likelihood of negative impacts on plants, animals, and soils in the area. Other benefits include reducing fuel consumption, vehicle and traffic movement and the risk of injury to the seismic crew associated with the deployment of cables. This extended abstract reviews the recent use of a cable-less system for Fleet Resources’ seismic acquisition conducted by Terrex Seismic in the Carnarvon Basin, WA, demonstrating the environmental, social, and safety benefits compared with traditional cabled systems for both 3D and 2D seismic programs. This extended abstract also draws on the experiences of Terrex’s use of the technology on behalf of UIL Energy and it explores the opportunities for capturing these benefits during the preparation of environmental and safety plans for regulatory approval.
Shaly sand rock physics analysis and seismic inversion implication
Authors: Widyantoro Adi , Saul Matthew
Published: August 2017

The analysis of well data from the Enfield field of the Exmouth Sub-basin, WA, indicates that both cementation and pore-filling clay appear to have a stiffening effect on the reservoir sands. The elastic contrast between brine sand and the overlying shale is often small and the large amplitudes observed from seismic data are associated with hydrocarbon content. More detailed rock physics and depth trend analysis of elastic and petrophysical properties, however, indicate significant spatial variability in the cap rock shales across the field with different sand shale mixtures, causing changes in the elastic response of the rock. Areas where shales are softer produce weak seismic amplitude contrasts even with high hydrocarbon saturation; the amplitude response being similar to areas with stiffer shales and brine-filled sands. The variations in reservoir quality are, therefore, masked by the distribution of the brine, oil and gas, as well as the variations in the cap rock. The Enfield rock physics analysis provides an example of reducing amplitude ambiguity over lithology-fluid variation and improves the chance of successful interpretation of the results of seismic inversion.
Examining the processing differences between P and P-S waves in a Rocky Mountain Foothills model
Authors: Rajput Sanjeev , Ring Michael
Published: August 2017

For the past two decades, most of the shear-wave (S-wave) or converted wave (P-S) acquisitions were performed with P-wave source by making the use of downgoing P-waves converting to upgoing S-waves at the mode conversion boundaries. The processing of converted waves requires studying asymmetric reflection at the conversion point, difference in geometries and conditions of source and receiver, and the partitioning of energy into orthogonally polarised components. Interpretation of P-S sections incorporates the identification of P-S waves, full waveform modeling, correlation with P-wave sections and depth migration. The main applications of P-S wave imaging are to obtain a measure of subsurface S-wave properties relating to rock type and fluid saturation (in addition to the P-wave values), imaging through gas clouds and shale diapers, and imaging interfaces with low P-wave contrast but significant S-wave changes. This study examines the major differences in processing of P and P-S wave surveys and the feasibility of identifying converted mode reflections by P-wave sources in anisotropic media. Two-dimensional synthetic seismograms for a realistic rocky mountain foothills model were studied. A Kirchhoff-based technique that includes anisotropic velocities is used for depth migration of converted waves. The results from depth imaging show that P-S section help in distinguishing amplitude associated with hydrocarbons from those caused by localised stratigraphic changes. In addition, the full waveform elastic modeling is useful in finding an appropriate balance between capturing high-quality P-wave data and P-S data challenges in a survey.
The petroleum resource rent tax (PRRT) and the economics of an oil and gas project
Authors: Franchina Carlo , Opie Ben
Published: August 2017

When thinking about the key drivers of project value, the PRRT profile of a petroleum project may not be top of mind for non-tax teams. As a 40% tax on the upstream activities of a petroleum project, however, the PRRT can significantly impact on project NPV and non-tax teams can play an important role in optimising the PRRT profile of a project. For finance and legal teams, this may be as part of the due diligence, modelling, and contract negotiation phase of acquiring or disposing of an interest in a project. Operational and technical teams can play an important role in helping tax teams to understand a project so that they can apply tax technical concepts; for example, in determining the characterisation of expenditure. Properly substantiating PRRT expenditure is also of critical importance; finance, IT, commercial, and operational teams should be involved in developing systems that capture the information tax teams require to be able to quantify and evidence PRRT deductions. This extended abstract focuses on the practical ways in which non-tax teams can help optimise the PRRT profile and, in turn, the NPV of a petroleum project.
Dry tree well flow assurance challenges and solutions for offshore gas condensate field development
Authors: Zhang Jeff , Kopperman Ian
Published: August 2017

Offshore field developments usually conceive that the dry tree wells (DTW) have less flow assurance challenges when compared with subsea development options. The relatively short vertical flow path for the DTW production risers causes fewer issues with respect to hydrate and wax management; however, the DTWs have particular flow assurance challenges due to dry tree well platforms design constraints. This extended abstract presents the various flow assurance challenges associated with the design and operation of DTWs for deepwater gas-condensate field developments, including:

the impact of production riser annulus thermal behaviour and soil modelling uncertainties on the topsides materials selection;
the coupling of low temperature propagation and cold liquid management issues topsides during cold well start-up; and,
the narrow operating window to establish the forward flow for the downstream systems following cold well start-up.

The absence of the capacity provided by subsea pipelines and flowlines, thus, leads to the requirement for integrated consideration of the DTWs and downstream topsides and potentially pipeline systems. The coupling for low temperature and liquid management issues, particularly for transient operations, requires rigorous flow assurance analysis. This extended abstract summarises the analytical solutions developed, applying the advanced flow assurance tools available, by considering the operating constraints, with the downstream process and export systems, to determine practical design solutions and operating philosophies.
Constraining fluid migration in low density data area: successful use of integrated modelling in the Southern Perth Basin
Authors: Langhi Laurent , Ciftci Bozkurt , Strand Julian
Published: August 2017

Constraining trap integrity or CO2 containment potential in areas with low density of data is challenging. We show here how the integration of hard data and modelling improved our understanding of the subsurface tectonic and stratigraphic architecture and ensured an initial definition of hydraulic behaviour of faults and fractures in the onshore Southern Perth Basin. A first-order geomodel was built based on interpretation of low-density 2D-seismic data and constrained by well, geophysical, and outcrop data. Forward stratigraphic models were deformed and implemented in the geomodel to predict the distribution of the phyllosilicate content. Membrane fault-seal prediction was performed based on the Shale Gouge Ratio algorithm to estimate the lateral migration potential. Characterisation of the stress state of fault planes was used to define the likelihood of reactivation and to predict vertical migration and caprock bypass. The elastic dislocation method was used to model the density and mode of failure of subsidiary sub-seismic faults that can impact on the caprock integrity. This was also used to constrain and validate the structural model. The integrated modelling significantly decreased uncertainties on the subsurface architecture and ensured the first-order definition of the CO2 migration and containment potential for the Wonnerup reservoir in the SW Hub. The maximum CO2 column heights supported by faults and potential leak points were estimated and migration scenarios and risks were defined.
3D microstructure characterisation of tight reservoir rocks and effective recoverable reserve estimation
Authors: Yang Sam , Wang Yudan , Mayo Sherry , Tulloh Andrew , Liu Keyu , Clennell Ben , Pervukhina Marina , Zhu Rukai , Li Ruru , Taylor John , Irvine Sarah , Maksimenko Anton
Published: August 2017

A data-constrained modelling (DCM) approach has been developed at CSIRO, which enables 3D characterisation of pores and mineral phase distributions using quantitative multi-energy synchrotron CT. For a tight reservoir, such as a carbonate limestone or a shale rock, DCM can generate microscopic partial volume distributions of materials and pores which are the effects of the fine length scales below X-ray CT resolution. Using this information, a quantitative relation between recoverable reserve and pore-throat size can be established for a rock sample. The technique can also be used for characterisation of other unconventional reservoir rocks.
Development of subsea tie-backs in challenging environments
Authors: Couper Gregor , Roshan-Zamir Sina , Rickman John , Lee Chris
Published: August 2017

Tie-backs to existing facilities are a long established method of expanding developments, as they often offer a cost-effective solution. For short length tie-backs located in regions that are remote and/or subject to severe weather conditions, however, the feasibility of installation can become a significant constraint. Factors such as high mobilisation cost of pipelay vessels and conditions that make pipeline towing impractical limit the potential design solutions. Defining these constraints early in the project is critical to successful execution. This extended abstract explores the challenges faced when developing such a tie-back by considering a case study of Origin Energy’s Geographe development, located in the Otway Basin. The location and harsh weather conditions constrained the viable installation options, which shaped the design. A flexible flowline was selected because it could be installed from a wider range of vessels and in a less limiting weather window. Subsea coolers are located at the wells for control of top of line (TOL) corrosion and to protect the flexible flowline from exposure to overly high temperatures. The cooler design brings its own challenges, requiring a two-stage process. First, modelling of the production fluid is used to determine the cooling requirements; then, CFD is used to design the cooler piping and structure to achieve this. A design with multiple, smaller structures was used to maximise the number of capable installation vessels. This extended abstract discusses the constraints that can occur, how the design must accommodate them, and the implications on execution of the project.
Do oil and gas risk owners understand real-world helicopter winch rescue hazards?
Authors: Macfarlane Mick
Published: August 2017

Helicopter search and rescue (SAR) for oil and gas operations in the northwest of WA is undertaken by helicopters and crews contracted to support oil and gas operations. The capability of these crews and aircraft varies and is described by helicopter operators as either limited or restricted SAR. This differs to similar oil and gas regions of Australia and globally, where full or dedicated SAR is available to respond to pre-identified rescue events.
Key differences between full and restricted SAR equate to WA operations being unable to conduct winch rescue at night from the water, limited capability to winch from vessels and lack or search technology such as night vision and heat signature equipment considered essential elsewhere.
The type of oil and gas operations undertaken in the northwest of WA are no different to other parts of the world, especially in terms of identified accident event potential. However, despite the need for full SAR as a preparedness measure for oil and gas emergencies overseas, northwest WA still operates to a lesser capability. There is much discussion as to the rational for this situation, but regardless of opinion logic would suggest, at the very least, opportunity exists to review northwest oil and gas risk management process for this specific field as development of increasingly complex and distant offshore operations continues. Therefore, this report, its supporting training materials and supplementary reports, seek to both clarify and reinforce hazards associated with helicopter SAR to enable more robust risk management going forward.
The integrated boardwalk: a tool for large capital project integration
Authors: Richer Aaron
Published: August 2017

Successful capital project execution of any size is a challenging endeavour. Performance gaps in on-time and on-budget delivery are often due to the inability to effectively integrate cross-functional work teams. Faced with delivering one of the largest capital projects in its portfolio, the leadership team of a large O&G asked: how do we best integrate 16 functional teams required to deliver this project? How do we get the right forums with the right audience as we are all busy? How do we build a culture of trust and performance transparency? In response, the team developed the integrated boardwalk approach as the way to run their business. The approach was for each of the 16 functional groups to build individual dashboards based on an agreed template of performance metrics. The dashboards are permanently visible performance boards in each work area. Senior leaders and leads would walk the performance boards spending no more than 15–20 mins at each. The intention is to provide an open and safe space for leads to talk about all aspect of their business as it relates to project readiness. Senior leaders drive the desired performance behaviours, where the functional leads highlight risks and specific barriers that leadership can act on and eliminate. The boardwalks have created a cultural change in the organisation, specifically:

people have the right focused forums to talk about their business with the right audience using the right data; and,
leaders have the transparency required to ask the right probing questions, recognise data-driven progress.
Leading through a major occupational health and safety incident
Authors: Witton Sam , Kelly Rowan
Published: August 2017

There are many examples of incidents that can happen to a business, entirely unexpectedly, that require an immediate response. When an incident occurs, the business will be on the back foot; planning the process of response is about having the skills to regain the upper hand. Key areas to consider:

First response: ensuring no further risk is created, establishing what has happened, and ensuring duties to preserve the scene are met.
Notification: requiring consideration of whether the incident is reportable to a government body, who is responsible for making the report, and what should be reported.
Planning: ideally, a pre-prepared crisis management plan will be in place; however, things evolve quickly. A re-assessment of the plan may be required. Planning is the opportunity to regain the initiative.
Investigation: this requires consideration of the purpose that the investigation is for. Providing support to workers involved in the incident, family members of the injured workers, and the crisis team.
Regulator engagement: the relationship with the regulator will be ongoing. Consider who is best placed to be the liaison. Shadow the regulator. Aim to be measured in your responses.
Media engagement: be prepared to engage with the media, if necessary, but do no expect them to deliver the message you want. Keep it simple. Avoid admissions.
The hydrocarbon potential of the 2015 Offshore Acreage Release Areas for petroleum exploration
Authors: Bernecker Thomas , Kuske Tehani , Lewis Bridgette , Smith Tegan
Published: August 2017

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. These areas are located across various offshore hydrocarbon provinces ranging from mature basins with ongoing oil and gas production to exploration frontiers. A total of 23 areas are released for work-program bidding and six areas for cash bidding (Fig. 1). The two work-program bidding rounds will remain open until 29 October 2015 and 21 April 2016, respectively, while cash bid submissions will close on 4 February 2016.
The 2015 Release Areas are located in 13 distinct geological provinces across eight basins and all were supported by industry nominations. Six areas are located in the Bonaparte Basin, two of which are cash bid areas over the Turtle/Barnett oil accumulations. In the Browse Basin, three areas in the Caswell Sub-basin and one area on the Yampi Shelf are released. In support of recent exploration activities and success, one large area has been gazetted in the central Roebuck Basin. The Northern Carnarvon Basin offering comprises 11 areas on the Exmouth Plateau and in the Dampier Sub-basin, including four for cash bidding. This year, the usual predominance of North West Shelf Release Areas is counterbalanced by seven large areas in the Bight, Otway, Sorell and Gippsland basins. This includes one area in the Ceduna Sub-basin, three areas in the deepwater Otway Basin, one area in the northern Sorell Basin and two areas in the southeastern Gippsland Basin. The nominations received for these areas highlights the industry’s interest in evaluating the hydrocarbon potential of Australia’s underexplored southern margin.
Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies.
2015 Onshore Petroleum Acreage Release
Authors: Divko Louise Goldie
Published: August 2017

Australian state and territory acreage opportunities and recent activities are summarised in this paper. Exploration opportunities continue to exist for petroleum explorers in onshore basins, including a number of sedimentary basins that have previously largely been overlooked, with an increased focus (and commercial success) on basin centred gas, tight gas and shale gas plays.
Access to onshore acreage in Australia for petroleum exploration is, in most jurisdictions, by means of a formal release process with a work program bidding system. Over-the-counter applications are available in some states based on perceived basin prospectivity.
Australian state and territory governments continue initiatives to encourage exploration to realise their natural resource endowments. This includes pre-competitive basin studies, cost-effective and speedy provision of digital exploration data, transparent regulatory regimes, provision of effective land access regimes, internationally competitive royalty regimes, and promotion of acreage releases nationally and internationally.
2014 PESA production and development review
Authors: Henzell Steve , Cooper Steve
Published: August 2017

2014 was the penultimate year for many of the massive multi-year LNG development projects. These projects will lift Australia’s LNG capacity by more than 250% from present levels. The first train of the Queensland Curtis LNG project came on-line in late 2014. Exports are expected to commence from a further three LNG projects (APLNG, Gladstone LNG and Gorgon) in 2015.
The ramp-up in gas demand on the east coast of Australia is spurring secondary development. A pipeline link has been proposed from the NT’s gas transmission system to connect to the east coast gas transmission system to allow gas from the Timor Sea to be fed into the east coast market and to the Queensland LNG projects.
2014 was a quiet year for new oil developments. Offshore, the Balnaves FPSO development was brought on-line. Onshore, the operators of the Cooper western flank continued to discover and develop a series of small fields. These small developments and better performance from some existing fields were able to offset natural reservoir decline elsewhere, leading to an overall increase in crude oil production of approximately 4% from the previous year.
The second half of 2014 was characterised by a decline in crude oil price from more than $100/BBL to under $60/BBL by year-end. For many LNG contracts, LNG price is linked to oil price; existing LNG developments are well progressed and are unlikely to be curtailed by the low commodity price, but future developments are already being slowed or stopped.
Sand production assessment considering the reservoir geomechanics and water breakthrough
Authors: Asadi Sadegh , Rahman Khalil , Pham Hoanh V. , Le Minh Thao , Butt Andy
Published: August 2017

Sand production assessment is essential from the early stages of field development planning for completion design and later for the production optimisation. Unconsolidated and weakly consolidated sandstones are prone to fail at a low flowing bottomhole pressure during hydrocarbon production. To predict the critical flowing bottomhole pressure or a safe drawdown, a geomechanical model that integrates in situ stresses, rock mechanical properties, the well trajectory, reservoir pressure, the production plan and the depletion trend is required. For a given stress field, well trajectory and production plan, the rock strength index is a key parameter that has significant impacts on the sanding risk.
This paper presents the results of a study investigating the potential of sand production from primary and secondary target reservoir rocks in a petroleum field in offshore Vietnam. A poroelastic analytical approach was used to investigate if sands will be produced from the open holes or perforations. The criterion of sanding was formulated to be the effective maximum principal stress to be greater than the effective rock strength. Observations of sanding or no sanding during drill stem tests (DSTs) were used to calibrate the sanding model to be used for sanding predictions of future production wells. The effects of reservoir pressure depletion on sanding risks were investigated using the stress arching theory. Since the water production from target reservoirs was observed in the nearby fields, the analysis was performed to investigate the effects of water production on rock weakening that may cause higher risks of sanding.
The results showed low risks of sanding for majority of the reservoirs, with drawdowns as high as 3,000 psi at the original reservoir pressure. The drawdown was, however, required to reduce to 500 psi to produce sand-free after depleting the reservoir by more than 90% of its original pressure. The results of this study led to the decision of completing the wells without using sand control equipment and to avoid sanding by controlling drawdown for the life of the well.
Chemical dispersants within an environment plan and oil pollution emergency plan: practically applying a risk-based approach
Authors: Dearden Mandy , Jivan Namek
Published: August 2017

Chemical dispersant use can be a valid response strategy for marine oil pollution events. This peer-reviewed paper describes how a risk-based approach to planning can be applied practically using the core concepts of risk assessment.
Comprehensive and systematic analysis is required in the environment plan to ensure that spill response strategies are in line with risk management requirements in the Offshore Petroleum and Greenhouse Gas Storage (Environmental) Regulations. In 2013, an APPEA working group identified the need for work to be undertaken that described this analysis for confirming the viability of chemical dispersant as a response strategy to support the mitigation of a marine oil pollution hazard.
A literature review and interviews with oil and gas operators, regulatory agencies and industry service providers provided the basis for the process development.
The result of this work is a process that is described in three parts: establish the context and risks; evaluate, demonstrate and define; and, implementation. Two flowcharts, and a description of each step, have been developed to assist planners in providing sufficient information to regulatory agencies assessing and accepting the use of dispersant operations.
The information collected during the planning phase in Figure 1 is the basis for the net environmental benefit analysis that is undertaken in the activation phase of a response (Fig. 2).
An outcome of this work is a process flow that oil spill planners can use to assess and plan spill response strategies that align with regulatory requirements.
Estimating appropriate levels of financial assurance for offshore petroleum activities in Australia
Authors: Horn David , Harrison Felicity , Woodhams Andrew , Taylor Miranda
Published: August 2017

APPEA has developed a method to assist titleholders estimate appropriate levels of financial assurance for pollution incidents arising from petroleum activities. In 2013 the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act) was amended to strengthen the polluter pays principles of the act and clarify and broaden its financial assurance requirements. Those amendments included provision for regulation requiring titleholders to demonstrate financial assurance as a prior condition for the acceptance of an environment plan (EP) by the National Offshore Petroleum Safety and Environment Management Authority (NOPSEMA). The Australian Petroleum Production and Exploration Association (APPEA) has developed a standard method that can be used by titleholders to estimate the level of financial assurance required under the OPGGS Act. The APPEA method broadly follows the approach first proposed by Oil & Gas UK in their Guidelines to assist licensees in demonstrating Financial Responsibility to DECC for the consent of Exploration & Appraisal Wells in the UKCS. The method involves two steps: (i) estimate the cost of well control (if appropriate); and, (ii) estimate the cost of the operational response. For the purposes of estimating the cost of operational response, a pollution incident is assigned to one of eight cost bands, according to its potential impact, based on three parameters: the hydrocarbon type, the total spill volume and the potential shoreline impact. The APPEA method was applied to 10 case studies, spanning a range of petroleum activities, hydrocarbon types and geographical regions. The case studies demonstrated that the operational response costs for each of the case studies are broadly captured by their respective cost bands.
Developing a reliable height function from the J-Leverett parameters to populate water saturation: a case study
Authors: Filippi Bert , Joodi Bahman , Sarmadivaleh Mohammad
Published: August 2017

Populating water saturation is a critical step in dynamic modelling. This work introduces a different height function that equates directly with the Leverett-J formula. In doing so, the model initialises under quiescent conditions without the need for end-point scaling. The resulting water saturation is a function of permeability, porosity, clay volume and height above the free water level. The Vcl—or clay content—is an important feature in this formulation because it compensates between extreme values of permeability and porosity.
This peer-reviewed paper describes how a single height function was sufficient to match the log-derived water saturation for all wells in the Coracle sand of the Surprise Field in the North Sea. The process involved fitting a simple height formula, with the least possible parameters, to the J-function calculated from all the special core analysis (SCAL) data. These parameters were then tuned to match the log-derived water saturation.
This technique was subsequently used in other fields where a single height function, which honoured the measured capillary pressures, accurately matched water saturation in all of the wells.
Multiphase sand erosion in standard elbows
Authors: Wong Chong Yau , Zamberi Amir , Shaffee Amira , Johar Zurita , Jadid Maharon , Boulanger Joan
Published: August 2017

Standard elbows are used to redirect multiphase flows in oil and gas facilities. Internal erosion of the pipe walls is expected when produced solids are present in the pipe system. The literature widely documents erosion modelling through empirical and numerical methodologies validated with experimental data on elbow erosion.
There are no studies documenting the full internal surface of standard elbows in multiphase flow erosion.
This peer-reviewed paper fills that knowledge gap through experimental erosion modelling of standard elbows at various multiphase flow conditions. The results provide a source of validation for numerical and analytical methodologies. Surface profiling of standard elbows at gas volume fractions (GVFs) from zero to one are studied.
Results suggest that erosion hot spots for all GVFs are located past an angle of approximately 45° from the flow inlet plane.
In gas only flows, moderate levels of erosion occur upstream of the erosion hot spot. All GVF conditions exhibit moderate levels of erosion downstream of the erosion hot spot. In liquid only flows, the erosion hot spot is at the extrados in the vicinity of the elbow outlet plane, and is not easily detectable by ultrasonic probes.
Comparison of multiphase experimental erosion pattern is made with computational fluid dynamics multiphase erosion simulations. A new relationship between the erosion rate of standard elbows and the reference cylinder-in-pipe data is proposed.
IEC 61511—functional safety in the process industry: the prominence of validation and verification in the lifecycle of a safety instrumented system
Authors: Derbyshire Andrew
Published: August 2017

As the concept of risk management has gathered momentum in the oil and gas industry during the past decade, so to has the adoption of IEC 61511, the internationally recognised standard for functional safety in the process industry. IEC 61511 is a risk-based standard that uses the concept of an electrical/electronic/programmable electronic based control system to implement autonomous means of risk reduction against a pre-defined unwanted hazardous deviation in a process.
While IEC 61511 has been in existence for more than a decade, the correct understanding and implementation of the standard to derive an effective demonstrate of compliance is still debatable.
The standard follows a cradle-to-grave approach to the lifecycle of any safety instrumented system and, unlike other standards where cherry-picking of the requirements may be carried out, IEC 61511 necessitates a demonstration of compliance to all lifecycle phases and their associated requirements.
The author of this peer-reviewed paper is fully aware of how difficult-to-digest the subject is; therefore, this paper on the prominence of validation and verification is presented in a pictorial, unambiguous and easy-to-digest manner while paying particular attention to the requirements defined for validation and verification in the standard. The topic of validation and verification in the overall lifecycle of IEC 61511 will be covered by the following questions:

What is the difference between validation and verification in the context of IEC 61511?

What is the difference between verification against IEC 61511 and IEC 61508?

When should planning for validation and verification happen?

When should validation and verification be carried out?

What are the implications of not carrying out validation and verification?

How does validation and verification fit into the wider context of the IEC 61511 lifecycle?

What level of independence is required for validation and verification?

The paper will also attempt to provide a practical example of how to implement an effective validation and verification strategy into an overall Functional Safety Plan to give the reader a clearer understanding of the obligations toward demonstrating compliance.
Using the wellbore as a d/p meter to calculate gas rate
Authors: Fair Chris , Flores Ricardo , Montague Eamonn , Hakim Bilal , Nande Soumitra , Zhumagulova Venera , Caylor Analicia , Draper Paul
Published: August 2017

The common use of high-resolution tree gauges and downhole permanent pressure/temperature gauges has made it possible to use the measured pressure drop in the wellbore to directly and accurately calculate the gas rate. This is accomplished by first combining an equation of state with a dynamic heat transfer model to create a phase-thermal model (PTM). The PTM is then integrated with a direct solution to the mechanical energy balance (MEB) for flow in pipes.
The results obtained using this technique can be as accurate as, or in some cases more accurate than, conventional rate measurements. Since the wellbore may also be used for fluid density validation, the effective gas gravity (an input for many conventional flow rate calculations) may also be determined during shut-ins and used as an input to improve the accuracy of meter provers.
The purpose of this paper is to explain the physics behind the gas rate calculation and to present case study results from the implementation of this method in both real-time and historic data processing. The paper will also discuss the limitations of this method and the range of potential applications.
Continental extension and break-up—using the Australian margins as a case study
Authors: McDermott Kenneth , Bellingham Paul , Graham Rod , Pindell James , Pryer Lynn , Cathro Donna , Horn Brian
Published: August 2017

The continental margins of Australia provide an excellent natural laboratory for investigations of continental extension and break-up, with examples of failed rifts, multi-phase extensional systems, and volcanic and non-volcanic margins. The thick sedimentary cover across large parts, however, has hindered understanding of the deep crustal and lithospheric structure due to poor imaging.
ION Geophysical has acquired deep, long offset seismic data across Australia’s North West Shelf, as well as the Bight Basin on Australia’s southern margin. These programs provide unique imaging of the deep basement structures and the complete overlying sedimentary section, and across all of the terrains from continental crust to oceanic crust.
The authors’ interpretation of these data will be discussed in the context of existing models for continental extension and break-up and the resulting implications for the petroleum system:

Models of hyper-extension and possible mantle exhumation will be discussed with regards to the Bonaparte, Browse and Bight basins.
Multi-phase extension and the development of intra-sedimentary detachment horizons will be reviewed across many areas.
Development of volcanic margins, including the effects of dynamic uplift and magmatic intrusions, will be investigated in the Exmouth Plateau.
Creation of enough accommodation space to allow the deposition of the observed (~20 km) sedimentary sections in the Carnarvon and Bonaparte basins.
Multizone monitoring well completion design in the GAB
Authors: Naldrett Garth
Published: August 2017

To provide the community with assurance that Santos GLNG operations are performed in a safe and responsible manner, the company has undertaken a major project to equip a large number of boreholes with multizone aquifer monitoring systems. These systems ensure aquifer water levels are monitored accurately.
To provide a cost-effective design that reduces the need for multiple wells and provides long-term data reliability, a packer and gauge system with full redundancy was designed and co-developed with Santos. The focus of this design was zonal isolation between aquifers, full redundancy, and retrievability.
This extended abstract describes a project where a fully retrievable seven-zone system was designed, deployed and monitored. Although the swell packers used to isolate zones are a mature technology, this is the first application where they have been designed to be recovered from the borehole with a pull-to-release system.
The design and deployment was especially complex as both the retrievable packers and 14 pressure temperature gauges were deployed in a slim 4 inch bore. The system was successfully deployed in the first quarter of 2014. A compact solar power surface acquisition system has also been integrated. It gathers and transmits the borehole data to an online portal. Santos is fully transparent with the data gathered and the local community is able to get this data from the online portal.
Northern Australia oil and gas: a new engine for Australia's prosperity?
Authors: Heyes Nicholas , Weijer Robbert de
Published: August 2017

The region of Australia comprising the area of the NT and northwest Queensland has significant conventional and shale resources that can see it emerge as the next major global oil and gas hub. According to the International Energy Agency (IEA), in the Asia-Pacific region, the natural gas production-consumption shortfall is expected to grow from 99.8 million tonnes per annum (mtpa) in 2012 to 251.7 mtpa in 2025 (IEA, 2014). Australia is well-positioned to cater to this growing demand, and is set to become the world’s largest LNG exporter by 2020. The northern Australia region can help to meet this growing global demand and also serve domestic east coast demand. Development of these resources would significantly accelerate the regional and national economy, but success will depend on doing it at a cost that is competitive with new sources of hydrocarbons from around the world.
This extended abstract outlines the natural advantages and challenges being faced by operators seeking to develop this region of northern Australia. Drawing on insights from global experiences, it identifies the key success factors and challenges faced in different regions during their development and commercialisation. It provides guidance and recommendations for maximising the development potential in northern Australia including:
new ways of working;
industry collaboration including sharing of infrastructure and data;
service provider development;
commercial partnerships;
better access to capital; and,
government support in tenure reform, incentives, tax benefits, capability development and investments in infrastructure.
Using innovation to lower gas gathering costs for unconventional projects
Authors: Nair Vishnu
Published: August 2017

Moving from conventional to unconventional gas project development requires a significant shift in approach. This presents challenges for operators making this transition, including standards and specifications being mis-matched to functional requirements, the need for robust surface and subsurface field development planning, lack of infrastructure, high construction and procurement costs and the scarcity of supply chain and logistics support. In their need to prove up sufficient reserves in time for downstream LNG plant operations, coal seam gas (CSG) players have neglected the development of appropriate standards, specifications and contracting and procurement strategies that consider how upstream costs can be minimised.
This can impact project viability in a high-cost, low-productivity environment. The requirement of shale gas development for continual expansion also presents challenges compared to conventional project development.
Adopting a factory approach can ensure a smooth and economic transition through the phase of continual shale gas production across the life of individual wells and through field expansion.
Using case studies, this extended abstract describes how innovation can be applied across the gas-gathering development phase of unconventional projects to achieve significant cost savings.
Key innovative opportunities include:

Maximising modularise construction and operation to reduce the construction schedule and maximise onsite productivity
Relocatable, interchangeable, standardised skid designs (design kit approach).
Standard modules sized to maximise container volumes (and they minimise freight costs)
Low-cost design Asian and Australian fabrication.
Fit-for-purpose technology and packages to lower operating costs.
Design and fabrication to minimise environmental impacts.
From play to production: the Cooper unconventional story—20 years in the making
Authors: Greenstreet Carl
Published: August 2017

The Cooper Basin is Australia’s leading onshore producing hydrocarbon province, having produced more than 6 Tcf of natural gas since 1969. The basin is undergoing renewal 45 years later, driven by the emerging growth of east coast LNG export-driven demand. Following North America’s shale gas revolution, the Cooper Basin’s unconventional potential is now widely appreciated and it is believed to hold more than 100 Tcf of recoverable gas.
This resource potential is held in four stacked target unconventional lithotypes, each having demonstrated gas flows:

tight sands—heterogeneous stacked fluvial sands;
deep coal—porous dry coals, oversaturated with gas;
shales—thick, regionally extensive lacustrine shales; and,
hybrid shales—mixed lithotype containing interbedded tight sandstones, shales and coals.

Industry activity initially focused on the Nappamerri Trough, where more than 25 contemporary exploration wells have been drilled, proving up an extensive basin-centred gas play with >1,000 m of continuous overpressured gas saturated section outside of structural closure.
Santos has had a team focused on unconventional resources for nearly 20 years and successful results have been quickly tied into the producing infrastructure. This has been demonstrated with the Moomba–191 REM shale success, Moomba–194 and the recent Moomba–193H connection, one of the basin’s first fracture-stimulated horizontal wells.
Prospective geology, existing infrastructure and market access makes the Cooper Basin well positioned for unconventional success. Each resource play is unique and commercial success requires considered adaptation of established technologies and workflows, based on a understanding of local geological and reservoir conditions. Commercialisation activity now seeks to define play fairways, characterise and prioritise reservoir targets and determine appropriate drilling and completion approaches.
FLNG—a nice niche?
Authors: Wilkes Martin
Published: August 2017

The LNG industry continues to experience strong growth. After a decade where industry growth outstripped expectations, even without the anticipated growth in LNG imports to the US, the outlook for LNG appears robust.
New markets and suppliers are emerging and market dynamics are changing, in particular the marked increase in short-term contracts and spot market trading. LNG developments historically have been land based. Increases in process train capacities have enabled economies of scale to be achieved, helping to mitigate rising costs. As a result of these economies of scale, the resource base required to support developments has also increased.
The development of FLNG together with a shift in market patterns presents the chance to fill a market space.
Though FLNG has a long way to go before becoming widely accepted as a standard development route. This extended abstract will:

Examine how different approaches to FLNG are being taken to fill the space left by traditional land-based LNG solutions.
Investigate the similarities and differences between FLNG developments and how the world floating production, storage and offloading (FPSO) fleet has developed in the last few decades, and will discuss the implications for FLNG development.
Examine how the changes in market dynamics may support the development of FLNG.
Outline the potential opportunities and challenges this could present to on- and off- shore producers in Australia.
Provide an overview of the possible future of FLNG.