bluuebunny/crossref_metadata_2025 huggingface dataset:
New heat flow data aids exploration in the Canning Basin, Western Australia
Authors: Ghori Ameed
Published: August 2017

The Geological Survey of Western Australia (GSWA) is providing new heat flow data and continuing studies in subsurface temperatures to understand the origin, migration and accumulation of geofluids in petroleum and geothermal systems of the Canning Basin. The study includes an investigation of subsurface temperatures from 274 wells, thermal conductivity measurement of 50 core samples from 22 wells, and single-dimensional (1D) heat-flow modelling of 101 wells. Thermal conductivity measurement of Canning Basin formations range from 1.06–5.83 W/mºC and modelled surface heat-flow ranges from 20–160 mW/m². The lowest measured thermal conductivity is in the Ordovician Goldwyer Formation at 1.06± 0.28 W/mºC, and the highest values are in the Upper Carboniferous Reeves Formation at 5.83 ± 0.22 W/mºC.
Generally, estimated heat-flow values are lower where thick sedimentary deposits are present such as the Fitzroy Trough, Lennard Shelf, and Kidson Sub-basin, with values less than 65 mW/m². The heat flow values increase to over 80 mW/m² on the Broome Platform and Jurgurra, Mowla and Barbwire terraces. Lower heat-flow values have been modelled in West Blackstone–1 (47 mW/m²), Curringa–1 (52 mW/m²), Kennedia–1, Napier–2 and Pearl–1 (55–52 mW/m²). Higher heat-flow values have been modelled in Goodenia–1, Lovells Pocket–1, Kanak–1, Cudalgarra North–1, and Cudalgarra–1, where heat-flow values are over 100 mW/m². These new thermal conductivities, corrected temperatures, and heat-flow values support improved modelling of the Canning Basin petroleum and geothermal systems.
Petroleum systems of the Bass Basin: a 3D modelling perspective
Authors: Arian Natt , Tingate Peter , Hillis Richard , O'Brien Geoff
Published: August 2017

Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin; however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal.
The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited; however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations.
The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources; however, Miocene reactivation is a major exploration risk in this area.
Risk reduction through advanced leak management
Authors: Stojic Silvio , Hanekom Antoine , Colman Russell
Published: August 2017

Leaks of hydrocarbon to the atmosphere can be a major facility safety risk and personnel occupational health and safety (OHS) risk for oil and gas producing and processing facilities. Normally closed valves that pass or leak in-line are also a major contributor to product loss and facility risk.
Component failures of these types have two common and challenging features: they are hard to find among the tens of thousands of potential leak sources, and the leakage rates either to the atmosphere or in-line can vary from minor to potentially catastrophic.
In the past seven to eight years, advanced methods for finding and managing leaks resulting from poor component integrity have been developed. This paper covers some of ATMECO’s accumulated knowledge developed over many leak surveys of both onshore and offshore oil and gas facilities. Typical statistical profiles of leaks from uncontrolled facilities are presented. The types of component failure that lead to leaks are discussed along with probabilistic analyses relating to the next likely failure.
Technologies of leak detection are reviewed, highlighting benefits and problems. Also discussed are the prerequisite data capture and management systems needed for a competent, robust and auditable system to manage component integrity.
Gas imaging technology is becoming one of the core hydrocarbon leak detection tools and also assists greatly in the analyses of leaks and in providing valuable input to remedial actions.
Survey design requirements for continuing and cost-effective component leak risk management are reviewed. Recommendations are provided about the preferred methods and management structures for programs designed to minimise component integrity risks.
Rock engineering systems adopted for sanding prediction in perforation tunnels
Authors: Younessi Ahmadreza , Rasouli Vamegh
Published: August 2017

Sand production is an important issue in reservoirs with weak or unconsolidated sand formations. Production of sand not only causes several problems in maintaining wellbore integrity but also is a problem during production where damages through the tubing and surface facilities are likely to occur due to the sand grains being transported along this path.
The rock engineering systems (RES), initially introduced in mining and civil related geomechanics problems, is one approach to analysing the interrelationship between different parameters involved in a rock engineering project. This is the approach that was adopted in this work to study and predict the sanding potential in perforation tunnels.
Sanding mechanism in perforation tunnels during production was reviewed and all effective parameters were identified. An interaction matrix was introduced to study the sanding mechanism through the interrelation between pairs of parameters. The interaction matrix was coded using a semi-quantitative rating approach to determine the interaction between each pair of parameters. The interaction intensity and dominance of each parameter in the system were studied through the cause-effect diagram to classify the parameters. This will assist in finding a better engineering action to mitigate or eliminate instabilities.
A sensitivity analysis was conducted on a data set, and major parameters playing in sand production in a perforation tunnel were identified using analytical formulae. The results of sensitivity analysis were compared with the cause-effect diagram derived from the interaction matrix. A good agreement between the two methods was observed. This shows the usefulness of RES for identifying potential sanding solutions through the interaction matrix analysis.
Carbon pollution (greenhouse gas) measurement and reporting
Authors: Gunst Andrew
Published: August 2017

Carbon reporting and emissions trading in Australia—both of which, in 2007, seemed unlikely—came into effect with the implementation of mandatory data reporting from July 2008 (Australia) and January 2010 (USA); the onus lies with emitting corporations to determine whether they must report. At the time of writing it is also likely that Australia and the USA will join Europe in placing a price on carbon by 2013.
The background to the Australian regulations will be explored in this paper, along with comparisons made to regulations in other jurisdictions, including the new reporting scheme in the USA.
To date, much of the public discussion in these countries has centred on the financial aspects of a carbon tax or emissions trading scheme; however, significant challenges exist in identifying and quantifying the emissions that the financial community seeks to trade, and business community understanding of the details of greenhouse emissions is not strong.
Case studies from the Australian oil and gas and related industries will be used to explain counter-intuitive aspects of greenhouse gas emissions and their regulation, and to illustrate challenges in emissions measurement and reporting.
Why your operator does not always love you: some observations on gross negligence, wilful misconduct and consequential loss
Authors: Rowland Stephanie , Douglas Bethwyn
Published: August 2017

Due to the nature of the role of operator under a joint operating agreement (JOA), the operator is potentially exposed to a large magnitude of risk. As a result, JOAs typically include clauses intended to allocate and limit liability between the parties.

A JOA may also include clauses that release the operator from liability and provide that the participants must indemnify the operator for liability that arises in performing its functions as operator. However, such clauses often contain carve-outs that attempt to make the operator liable if loss is caused where the operator’s conduct, or that of its senior personnel, constitutes gross negligence or wilful misconduct.

Given the magnitude of loss that may potentially be incurred by participants under a JOA, it is vital that participants understand the impact of their JOA on their exposure to liability and, in particular, the current interpretations of the terms gross negligence and wilful misconduct likely to be applied by Australian courts.

This paper considers the practical operation of such clauses and explores:

the ability of a participant to claim consequential loss against the operator and what type of loss is likely to constitute consequential loss; and,
practical avenues available to participants of a JOA to minimise the risk of liability by way of drafting, including the effect of a limitation of liability clause on the ability of a JOA participant to recover from the operator.
DeepStar case study: flowline burial for insulation
Authors: Golczynski Tommy
Published: August 2017

Canyon Offshore, Multiphase Solutions and ASGM Engineering recently completed a study for DeepStar to assess flowline burial for insulation for oil and gas deepwater subsea tiebacks with high-pressure/high-temperature (HPHT) reservoir characteristics. The primary goal of the study was to document the scope of application, added value, and schemes for successful implementation of burial for insulation of deepwater HPHT flowlines.
The prize in oil production is the extended cool-down time (three plus days), which can potentially reduce the number of occasions where flowline cold shut-in preparations are necessary. The principal prize in gas production is ability to deliver high water-rate gas production, by removing the need for continuous hydrate inhibitor and extending production beyond the point where inhibitor delivery is inadequate.

Lateral and upheaval buckling analyses assessed the expected interaction between flowline, soil and movements associated with expansion due to temperature. Controlled installation sequencing to allow for lateral buckling during the initial startup phase was evaluated to mitigate the risk of excessive bending strains and upheaval buckling in the flowline from thermal expansion. The results indicate installation methodologies can achieve reduced bending strains and avoid upheaval buckling.
Net present value (NPV) calculations were tabulated for the various tieback scenarios to assess the economic merits of flowline burial versus non-burial.
The results of the study indicate that burial provides improved thermal insulation characteristics and yielded positive NPV, compared to unburied flowlines. The risk of thermal-induced lateral and upheaval buckling can be mitigated using identified techniques during the installation phase of the work to avoid undesired high bending strains.
Model centric production management systemsy—opportunity and challenges
Authors: Scanlon Michael , Sharma Vikram , Zangl Georg
Published: August 2017

While modelling technology is routinely used in oil and gas to control and optimise process facilities and downstream plants, the upstream sector has been slow to adopt model-based control systems, or the models are very coarse and mono-dimensional, reducing confidence in their predictive capability.
Further, the models are discipline specific, and the interdependence between the subsurface and the surface is poorly evaluated. This is particularly relevant to coal seam gas developments, where well productivity planning and management needs to be considered in the context of the complete production value chain, and the dependencies between the gathering system and the processing plants considered in optimising the contract nominations.
A key breakthrough technology will be a model-based control system that can assimilate all the available data, put the data into context, represent the full value chain, assess the relative impact of the components of the production train, and then assess the decision alternatives in the context of deliverability, processing cost, HSE and market opportunity in sufficient time to have an impact.
Advances in data acquisition, transmission and storage, coupled with advances in computational efficiency and software engineering, mean that integrated modelling systems are realisable today.Collaboration between technology providers has delivered software tools that offer a unified perspective across the subsurface, surface gathering systems and facility worlds.
The presentation will explore the technology capability, the application opportunity and organisational requirement to fully realise the potential of integrated asset models.
A decade of sectoral initiative to promote consistent and reliable quantification of greenhouse gas emissions
Authors: Ritter Karen , Keating James , Shires Terri , Lev-On Miriam
Published: August 2017

With the increased focus on greenhouse gas emissions (GHG) and their role in the implementation of policy measures for their mitigation, there continues to be a need for accurate, reliable and transparent characterisation of these emissions. A myriad of mandatory reporting regulations and voluntary initiatives with diverse protocols and methodologies are emerging globally. This poses a particular challenge to multinational companies, such as in the oil and natural gas industry sector, which operate globally and in joint ventures.
The American Petroleum Institute (API) and its member companies recognised these challenges over a decade ago and launched a multi-year initiative to map out and provide tools for the quantification of GHG emissions from oil and natural gas industry operations and similar industrial sources. During this time span, the industry developed several key guidance documents to promote the consistent and accurate quantification and reporting of GHG emissions.
This paper will focus on two recent publications:

the 2009 Edition of API’s Compendium of GHG Emissions Estimation Methodologies for the Oil and Gas Industry (3rd revision); and,
a new document addressing technical considerations and statistical calculation methods for assessing the uncertainty of GHG emission estimates.

The paper will discuss case studies pertinent to oil and natural gas exploration and production activities and will put these in context with emerging US mandatory GHG emissions reporting. It will also discuss the broad applicability of these estimation methods, and uncertainty considerations, to most industry sectors that rely on fossil fuels for their energy sources.
Time-transgressive fault evolution and its impact on trap integrity: Timor Sea examples
Authors: Ciftci Bozkurt , Langhi Laurent
Published: August 2017

Top and fault seal failure represents an exploration risk in the Timor Sea where hydrocarbons are typically associated with hourglass structures. These structures comprise two distinct systems of conjugate normal faults that formed by 1st-phase (late Jurassic) and 2nd-phase (Neogene) extensions. Horst blocks bounded by 1st-phase faults potentially trap hydrocarbons and are overlain by grabens bounded by 2nd-phase faults. The two fault systems generally merge and intersect in dip direction to form the composite and time-transgressive faults of the hourglass structures. The 2nd-phase of extension is seen as the dominant cause of the seal breach.
Revaluation of a series of hourglass structures on the Laminaria High confirmed two distinct sections of syn-kinematic strata. Bases of these sections correspond to maximum throws on the fault planes where the faults were probably nucleated. The presence of negative throw gradients upward and downward from the throw maximums indicate syn-kinematic deposition and fault growth, respectively. Assessment of these trends suggests that the 1st and 2nd-phase faults were detached at the onset of the 2nd-phase of extension. Connection was predominantly established by down-dip growth of the 2nd-phase faults while the reactivation of the 1st-phase faults may have remained minor.
Seismic evidence of leakage from attribute mapping is used to constrain the timing of fault linkage and to validate prediction of leaking fault planes. It was noted that downward propagation of the 2nd-phase faults towards the hydrocarbon traps stresses the top seal integrity due to fault tip deformation front and development of sub-seismic fractures.
Woodside and contractors—partnering for safety excellence
Authors: McQueenie Jim
Published: August 2017

Oil and gas industry safety performance in Australia compares well with other industries. Performance of the Australian Oil and Gas Industry, however, as reported by APPEA, lags behind the average performance of the international industry, as reported by the International Association of Oil and Gas Producers (OGP). The improving trend in health and safety performance in Australia over the last ten years is continuing, but progress is slowing. This slow-down suggests that if we continue to work in the same manner as we have done in the past, we will not create the shift in performance required to match or better the international industry average.
The current structure of the industry has a number of different operating companies supported by a broad base of contractors. In 2009, contractor exposure hours accounted for 88% of the total hours worked by Woodside.
Each operator and contractor has their own approach to health and safety management.
The industry backdrop is an increase in activity driven by coal seam gas (CSG) exploitation, a number of LNG megaprojects in development in Western Australia, a significant proportion of senior personnel retiring from the industry, and a significant influx of people new to the industry to support expansion and replace retirees. This will increase demands on existing, already stretched, industry resources and could reduce our ability to develop new approaches and effectively implement them.
One of the actions taken to address this at Woodside has been to engage over 100 senior leaders in our company and the CEOs of all of our major contractors to build a commitment to change the basis upon which operator and contractor work together on health and safety issues. This has involved establishing industry sector focus groups for: drilling; exploration and geomatics; onshore project construction; offshore project construction; and, production. Each group is comprised of Woodside and contractor leadership.
Given the success of these groups in formulating and driving their own agendas for improvement, and given the strong (and quite pleasing) contractor desire for ownership, Woodside sponsorship will cease at the end of 2010.
The approach aims to create sustainable, self governed health and safety focus groups to develop industry solutions to our industry’s health and safety challenges. The groups operate on the premise that excellence in health and safety performance is of mutual benefit and is non-competitive.
Using time-lapse seismic to monitor injection of CO2 into a depleted gas reservoir—Otway pilot project
Authors: Urosevic Milovan , Pevzner Roman , Shulakova Valeriya , Kepic Anton , Sharma Sandeep
Published: August 2017

The CO2CRC Otway Pilot project involves the injection of over 65,000 tonnes of CO2/CH4 gas mixture (80% of carbon dioxide and 20% of methane) into a deep depleted gas reservoir. The test site is located onshore, some 300 km west of Melbourne. CO2 injection into a depleted gas reservoir will provide important experience for monitoring and verification under these conditions.
In this study we address the application of time-lapse seismic for assurance monitoring, which aims to verify that the injected gas remains confined to the target formation. Moreover, we also attempt to image CO2 plume within the reservoir. This is particularly challenging due to the small size of the reservoir and the associated CO2 plume, the presence of residual gas saturation, as well as the significant depth and complexity of the reservoir. In order to meet these challenges we developed a comprehensive seismic monitoring program, which included both time-lapse surface and borehole seismic methods.
Prior to the base line survey, a series of 2D test surveys was conducted that aimed to investigate seismic repeatability at the site. It was crucial to keep the repeatability at the highest level considering that the time-lapse seismic signal was expected to be quite small. In fact, it is widely adopted that injection of CO2 into a depleted gas reservoir or equivalently enhanced methane recovery is not traceable by repeated seismic measurements.
Careful planning of 3D surveys allowed us to achieve excellent repeatability, which is at the reservoir level represented by normalised RMS difference values of about 20%. Single, coherent time-lapse anomaly at the reservoir level was observed; its location and amplitude agree with the position of CO2 plume predicted by reservoir simulations. Measured amplitude differences agreed with the one predicted by seismic modelling.
Turning CSG into LNG into reality
Authors: Khalil Majid
Published: August 2017

Energy demand is expected to grow further. Given increased environmental concerns, natural gas will have a heightened role in the future. In 2006, natural gas constituted 22.9% of the global energy mix and this is forecasted to increase annually by 1.6%. The industry will need to tap unconventional resources primarily from CSG reserves.
Given the high cost environment seen in the industry in recent years, coupled with the current global economic recession, delays in FID decisions will mean a tight market situation post-2014. Therefore, it is important that the CSG to LNG proponents surmount the inherent challenge of developing the unconventional resources to meet the growing market needs.
An LNG development carries with itself commercial and technical challenges across the integrated chain. With the added intricacy of developing large scale CSG reserves, it is very important that the CSG to LNG proponents understand the complex nature of an integrated LNG development.
The development of Malaysia LNG (MLNG), MLNG Dua and MLNG Tiga in Malaysia and ELNG in Egypt involved a total of 10 LNG trains equating to approximately 32 Mta of volumes. PETRONAS offers 30 years experience in developing large scale integrated LNG projects from wellhead, pipelines, liquefaction and re-gasification facilities.
Although the techno-commercial understanding of the integrated LNG project is a must-have, what cannot be ignored is the need for a well co-ordinated collaboration among all key stakeholders, between the individual project developers, the community, LNG customers, and, importantly, the authorities, in order to enable the economic benefits to be shared.
Delivering upstream gas developments in Papua New Guinea—challenges and lessons learned
Authors: High Simon
Published: August 2017

PNG is a unique environment and culture that presents some intriguing risks and challenges in project delivery. Clough has delivered 68 projects in PNG over the past 26 years and is recognised as one of the most experienced contractors in the region. The company has been involved in all major PNG upstream gas developments including Hides, Kutubu, Moran and Gobe.
Clough is currently delivering the upstream infrastructure for ExxonMobil’s US$11 billion PNG LNG project. This paper will use case studies from Clough’s 26-years of experience in PNG to review the key challenges and define strategies used to overcome these challenges in order to deliver PNG’s largest ever resource project.
Key challenges include:

Logistics—most of the gas reserves in PNG are difficult to access and located at very high elevations. For example, the Hides wellpads for PNG LNG are located approximately 2,700 m above sea level and accessed by a rough and dangerous road.
Security—overcoming security risks including community unrest and the existence of armed bandits on key supply routes.Landowner issues—how to work with PNG’s local communities to ensure they are happy with project outcomes to reduce landowner issues.
Training local labour—equipping the local workforce with the skills required to deliver the project to Australian standards, which provides life changing skills for the local community.

Key to Clough’s continued success in PNG has been its ability to effectively capture lessons learned on all completed projects and apply this knowledge to improve future project outcomes. Critical lessons will be communicated during this presentation.
Revisiting petroleum systems in the Gippsland Basin using new geochemical data
Authors: Volk Herbert , Ahmed Manzur , Boreham Chris , Tingate Peter , Sherwood Neil , Liu Keyu , O'Brien Geoffrey , Edwards Dianne
Published: August 2017

The Gippsland Basin is one of the most prolific petroleum provinces in Australia, yet the understanding of source, migration and secondary alteration of petroleum is often based on data and concepts that have been developed decades ago. For instance, the Gippsland Basin is commonly cited as an explicit example of a province dominated by oil from coal, yet there is no literature using molecular and isotope geochemistry explicitly demonstrating that generation and expulsion has been from the coal seams and not the intervening carbonaceous mudstones.
In this study we will present insights from the evaluation of quantitative analyses of aromatic hydrocarbons, which will be evaluated together with low molecular weight hydrocarbon distributions from whole oil gas chromatography and aliphatic biomarker distributions of the oils. Oils are commonly incrementors of different charge events, and hence extending molecular and isotopic information from a wide molecular weight range offers a more detailed insight into the charge history of an oil field. Oil-bearing fluid inclusions are additional archives that hold keys to the fill history of petroleum reservoirs, and this contribution will also present new data on the distribution and composition of palaeo-oils trapped in fluid inclusions. Lastly, examples will be presented of how modern tools for analysis such as compound specific isotopic analysis (CSIA) of n-alkanes and isoprenoids as well as how understanding relationships between organic facies and source rock kinetics can contribute to refining our understanding of petroleum systems in the Gippsland Basin.
Deepwater Exmouth Plateau, North Carnarvon Basin: preliminary investigations into ridge and furrow features
Authors: Day Kevin , Gale Julie , Smallwood John
Published: August 2017

Numerous fields of long, shallow subsurface linear ridge and furrow features were mapped during the interpretation of a 3D seismic dataset covering Hess Exploration Australia Pty Ltd’s WA–390–P deepwater Exmouth Plateau permit. These kilometre scale features are often slope parallel and have separations of between 100 to 400 metres between ridge crests. Heights range from the limit of seismic resolution up to approximately nine metres. Similar linear shallow subsurface features have been interpreted in the North Falkland Basin in Desire Petroleum’s Tranches C and D permits. Initial investigations suggest that these features appear similar to the Holocene and older mega furrows/palaeo-mega furrows identified along the lower slope/rise in the Gulf of Mexico, most notably along the base of the Sigsbee Escarpment, and along other continental slope/rise settings.
Evidence of seabed and shallow sub-seabed sediment instability in the form of slumps and slides together with the effects of shallow sediment deformation and dewatering are also visible across the WA-390-P area. Ridge and furrow features from the deepwater Exmouth Plateau area are described in detail alongside examples from the North Falkland Basin. It is suggested that interaction between gravity driven downslope processes, sediment dewatering and alongslope sedimentary processes could be a possible mechanism of formation for these features. Horizontal and vertical delineation of these features can contribute towards regional understanding of subsurface sediment instability.
Temperature-dependent stability of deep wells in the Cooper Basin
Authors: Fernandez-Ibañez Fermin , Castillo David , Wyborn Doone , Hindle Dean , White Adrian
Published: August 2017

The Cooper-Eromanga Basin is characterised by high heat flow that has been related to the presence of high radiogenic heat-producing granites. Several wells have been drilled in the area to exploit the heat from the fractured granitic rocks of the basement. Drilling through the hot formations in the Cooper Basin (max. temperature ca. 250 °C) with relatively cool drilling fluids induces an almost instantaneous cooling of the wellbore wallrock. Cooling of the hole (the usual case) increases the tensile stresses (and decreases the compressive stresses) at the wellbore wall. The magnitude of the thermal stresses is also dependent on the silica content of the formation.
Modelling of the in situ stress tensor and mechanical properties of the wellbore rocks has revealed the time-dependent effect that the borehole collapse pressure has on the stability of the wells. Narrow breakouts form at the time of drilling. Afterwards, the temperature difference (ΔT) decays with time, and as the hole warms up compressive stresses increase and breakouts become enhanced. Therefore, if a high ΔT and a short well exposure time are achieved, it would be possible to inhibit breakout development, drill with a lower mud weight (eventually underbalanced), and, thus, minimise the risk of formation damage.
Utilising current technologies to understand permeability, stress azimuths and magnitudes and their impact on hydraulic fracturing success
Authors: Johnson Raymond , Glassborow Brent , Meyer Jeremy , Scott Michael , Datey Ashish , Pallikathekathil Zachariah
Published: August 2017

In coal seam gas exploration and appraisal, stress and permeability are often inter-related and play a large role in deliverability, particularly affecting hydraulic fracturing effectiveness. Generally, the structural setting for a coal seam gas (CSG) play can be defined by indirect data such as petroleum wells, core wells, or seismic data; however, the viability of a structure to be highly conducive to CSG development also requires direct measurements to fully define the effects associated with this interdependency of stress and permeability. Unfortunately, this interdependency may not be as apparent during the exploration phase as within the planning, execution and evaluation of a hydraulic fracturing program.
We will present data from a limited area of the Surat Basin, in the Walloon coal measures, where initial regional and well data were available to allow drilling to evaluate a small, localised, structural setting for CSG development. While some permeability data were encouraging in the initial program, subsequent drilling indicated that permeability might become variable across this structure. Thus, further investigations were made and included novel, cross-dipole sonic logging in combination with acoustic and more advanced resistivity imaging logs. These data indicated that the stress and permeability azimuths may be aligned to take advantage of hydraulic fracturing. Thus, a hydraulic fracturing program was initiated in this area incorporating diagnostics to understand the potential benefit of this technology.
The results of this program, while localised, do indicate that a potential pitfall can exist in some environments where the stress magnitudes along with stress and dominant permeability axes are not ideally positioned to take advantage of hydraulic fracturing. We will show how the data in this case were acquired, evaluated and integrated to support the overall understanding and interpretation of the results. Due to space constraints, this paper focusses primarily on the overall data process and is unable to elaborate fully on all diagnostics used and the fullness of their determinations; however, adequate supporting evidence is supplied in order to illustrate the problems in executing and achieving effective stimulation in similar structural settings.
State of the art technology for subsea tie-in and repair systems in the North Sea
Authors: Nesje Per A.
Published: August 2017

The new design of subsea structures such as riser bases (RB), pipeline end terminations (PLET) and pipeline end manifolds (PLEM) has resulted in lighter and more installation-friendly solutions.
PLETs and PLEMs can be installed together with the pipeline, avoiding separate installation campaigns. The RB is designed to slide on the seabed, hence it can be connected directly to the pipeline, avoiding the need for expansion spools.
If dropped object and/or trawl protection is required, a range of standardised GRP protection covers is available for the protection of structures, inline/hot-tap tees and spools.
A new remote controlled tie-in system—THOR—has been developed for general use. The concept offers significant cost savings when measured against the existing conventional tie-in tool based systems. The system will be available for all pipeline sizes and will be independent of connector manufacturer.A vertical system for hot-tapping and tie-in onto a hot-tap tee has been developed and installed on the Ormen Lange field. The system includes a contingency isolation plug for recovery of the isolation valve module.Active pipeline supports (APS) have been introduced to the market and are now installed on several projects. This type of structure will enable the adjustment of pipelines during and after installation, and will therefore ensure more flexibility during the design phase.
The pipeline repair system developed for the North Sea has been used for 20 years and is definitively field proven through a large number of repair operations and planned work. Many repair components and their associated installation systems have been made and used over these years. Based on this knowledge we can now better recommend, to a new repair market such as Australia, which type of repair items to purchase for the local repair system.
This evaluation will also identify the items or components that should be partly prepared, either on a design level only, or up until storage of forged material or completion of particular long lead items.
Improve operational effectiveness with operations management systems
Authors: DeVries Stan , Gopu Victor
Published: August 2017

This paper looks at three examples that demonstrate how smart operations can reduce the uncertainty to reliably contribute to sustained growth in operations effectiveness.
These relate to:

demand/capability change;
critical asset management; and,
adaptive collaboration across processing/production areas and sites.

While many heavy process industry organisations try to measure and manage the processing/production facilities using the operations effectiveness phrase, many have encountered difficulty in delivering the desired business improvement—whether it is achieving, sustaining, evolving or rolling out. This paper proposes a re-think based on successes in several industries. This paper defines what working smarter really means through making earlier and better decisions that affect the current performance of the processing/production facility and the supply chains. These decisions are often balancing naturally conflicting demands, both between facility and supply chain and between present and future events.
Geological overview of the 2011 offshore acreage release for petroleum exploration
Authors: Bernecker Thomas
Published: August 2017

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2011, 29 areas in eight offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or 12 months after the release date (i.e. 13 October 2011 and 12 April 2012)–this depends on the exploration status in these areas and on data availability. The 2011 Release is the largest since the year 2000 with all 29 areas located in Commonwealth waters offshore NT, WA, Victoria and Tasmania, covering about 200,000 km2. The producing hydrocarbon provinces of the Carnarvon, Otway and Gippsland basins are represented by gazettal blocks that are located close to existing infrastructure and are supported by extensive open file data-sets. Other areas that are close to known oil and gas discoveries lie in the Caswell Sub-basin (eastern Browse Basin) and on the Ashmore Platform (northwestern Bonaparte Basin). A particular aspect of the 2011 release is provided by 13 areas in under-explored regions offshore NT and WA–all of which range from 100–280 graticular blocks in size. These areas, located in the Money Shoal, outer Browse, Roebuck, northeastern Carnarvon, Southern Carnarvon and North Perth basins, offer new opportunities for data-acquisition and regional exploration. The release of three large areas in the Southern Carnarvon and North Perth basins is supported by new data acquired and interpreted by Geoscience Australia as part of the Offshore Energy Security Program, which selected results are being presented at this year’s conference.
Australian states and Northern Territory acreage update at APPEA 2011
Authors: Tinapple Bill
Published: August 2017

Bill’s presentation is on behalf of the NT, Queensland, NSW, Victoria, SA and WA. Some highlights are:
• NT: 24 onshore exploration applications were received in 2010 (an increase of 50 % from 2009). About 479,100 sq km of the NT is now under application, including grassroots areas.
• Queensland: In 2011, a variety of exploration opportunities are being offered in basins ranging in age from Precambrian to Cretaceous. Targets include conventional oil and gas as well as shale gas.
• NSW: There are now more than 800 unallocated petroleum exploration blocks, including the Darling Basin, the Tamworth Moratorium area, and the Oaklands Basin Moratorium area.
• Victoria: Acreage release is proposed for the onshore Otway Basin in 2011.
• SA: The CO2010 acreage release, comprising three blocks in the Cooper and Eromanga basins, closed on 10 March 2011.
• WA: To coincide with the APPEA Conference, acreage has been made available for bidding from the Canning Basin, Northern Carnarvon Basin, Officer Basin and Perth Basin.
Production system analysis for Woollybutt mature oil field using dynamic simulation
Authors: Yokote Ryosuke , Donagemma Vanni , Mantecon Juan Carlos
Published: August 2017

This paper describes how multi-phase flow dynamic simulation techniques were applied to support and optimise the day to day production operations for the Woollybutt oil field on the North West Shelf, Australia. Eni Australia is the operator of the: Woollybutt oil project, which consists of two separate fields; Woollybutt North, which has three production wells; and Woollybutt South, which has one production well– Woollybutt–4H (WBT–4H). WBT–4H is located about 7 km from the floating production storage and offloading (FPSO) facilities and shares the production flowline with two other production wells from the Woollybutt North field. Production from WBT-4H accounts for more than 60% of the total production. For this reason, achieving steady production from this well is the highest priority for the operations.
To understand the hydrodynamic behaviour and to maximise production from WBT–4H, the production system for the Woollybutt South field was modelled from WBT–4H reservoir inflow points to the FPSO using a commercial dynamic simulation software package. The model successfully matched the pressures measured at the permanent down hole gauge (PDHG) and upstream production subsea choke dynamically, using the arrival pressure at the FPSO and the measured gas lift rate at the FPSO as input data. The model was used to identify the reason for slugging , to locate where the slugging conditions were originating, as well as to investigate optimum gas lift rate and the impact of bringing other wells on production from the Woollybutt South field. Furthermore, the model was used to identify the cause of sudden severe slugging, which forced to reduce the subsea production choke opening. The simulation work concluded that an unstable gas injection at the gas lift orifice valve (GLOV) induced severe slugging. This conclusion was validated operationally in the field soon after.
Results of the multi-phase flow dynamic simulation provided good understanding of the hydrodynamic behaviour in the production system and are used to make informed decisions to support and optimise the day to day production operations.
Cost reduction of subsea gas production systems using emerging hydrate remediation technology
Authors: Sheil Henry , Young Peter , Richardson Martin
Published: August 2017

Gas flowlines are presenting flow assurance challenges in hydrate management resulting from low ambient seawater temperatures in an increasing number of deepwater developments. When the equilibrium hydrate temperature of the produced fluid is above the minimum seabed temperature, and the hydrate inhibition system fails, there is a risk of hydrate blockage in the subsea system.
The industry-preferred approach for hydrate blockage remediation is dual sided depressurisation (DSD). The objective is to depressurise the flowline below hydrate onset conditions, thus allowing hydrate dissociation and safe disposal of the gas inventory. This is generally performed by one of two methods: installation of a dual flowline system for facility-based depressurisation (CAPEX impact) or by connecting a mobile offshore drilling unit (MODU) to an appropriate wellhead or christmas tree (XT) to allow simultaneous depressurisation at the MODU and the facility (OPEX impact).
It is recognised that both methods incur significant costs. Typically the cost, schedule and availability uncertainties of bringing in a MODU to solve these production stoppages are too high. Consequently, subsea developments often select the increased CAPEX option.
An optimisation of the MODU-based intervention method is the subject of this paper. The feasibility of using a lightweight intervention vessel (e.g. an offshore support vessel) in place of the MODU is investigated. In discussing this optimisation, this paper also presents an introduction to hydrate remediation theory, some practical challenges, case studies and vessel requirements.
Environmental monitoring programs on recent capital dredging projects in the Pilbara (2003–10): a review
Authors: Hanley Russell
Published: August 2017

Since 2003, there have been 12 capital dredging projects approved within the Pilbara region (combined total volume of material = ˜70 Mm3). Two projects did not proceed, seven have been completed, and three are underway. This unprecedented flurry of dredging activity in Western Australia is not finished yet, with several large projects pending approval. A review of ministerial statements granting approval for each project reveals that conditions governing environmental monitoring programs have become increasingly more comprehensive, more prescriptive, and more onerous since 2003. Conversely, the reporting timeframes have significantly contracted, particularly for coral health monitoring. A review of the compliance reports for each project was unable to find evidence of any breach (non-compliance) of the permitted levels of environmental impact. In addition, the monitoring programs reveal that predicted (approved) levels of impact on coral for each completed project did not occur. The review concludes that overestimations in the modelling of plume behaviour often lead to unrealistically large predicted areas (zones) of impact and influence. Thresholds of total suspended solids (TSS) used for predicting levels of coral mortality, however, are where the gross overestimates of impact routinely lie. Many problems flow from large overestimations of coral mortality, including: impacts on the value of monitoring study designs; the total cost of monitoring programs; health and safety issues; and, the cost of offsets packages. A better approach is outlined, which highlights the value of tailoring the environmental monitoring programs to fit the characteristics of each project, and the characteristics of the particular suite of marine organisms to be monitored.
Eromanga (Queensland) exploration–new concepts for an old basin
Authors: Lowry David , Evans David
Published: August 2017

Eromanga Basin exploration surged in Queensland after the discovery of the Jackson field in 1982, but has ebbed over the last 20 years. Perceived exploration risks are:

• Oil generation and migration peaked in the mid-Cretaceous before much of the anticlinal structuring, so that modern structure is an uncertain guide to Cretaceous migration paths.
• Permian coals are generally credited with sourcing most of the oil and gas in the Cooper-Eromanga Basin. In Queensland, the Permian largely drains to the southern flank and the northern flank is thought to have a high charge risk.

This study covers 100,000 km2. It used sonic logs to determine the amount of Tertiary erosion and thus allows the preparation of structure maps restored to mid-Cretaceous time. Maturity maps of the Birkhead and Poolowanna Formations were computed from a reflectance/restored temperature algorithm based on 50 wells. Source rock thickness maps and an oil expulsion model based on Pepper and Corvi (1995a, 1995b) then allowed oil expulsion to be mapped regionally.
The study produces the key results that could be expected from 3D earth modelling, but with great savings in time and money.
The study demonstrates an oil kitchen at both Poolowanna and Birkhead stratigraphic levels in the vicinity of Tanbar–1. Secondary migration losses are speculative, but modelling shows that hundreds of millions of barrels of oil from each formation have migrated west towards the Curalle ridge, north to Inland and Morney, and southeast to Mt Howitt. The Inland oil field is presently an isolated anomaly on the northwest flank of the basin, but this study suggests that further exploration in the area could be successful.