bluuebunny/crossref_metadata_2025 huggingface dataset:
Near real-time geomechanical modelling update and completion optimisation in the fold belt area of PNG: a case study with Oil Search Ltd
Authors: Burgdorff Katharine , Castillo David , White Adrian , Rowse Jon , Douglas Gavin , Dow Mike
Published: August 2017

Collecting high-resolution image data in the majority of currently-drilled wells in the Papuan Fold Belt area has substantially improved our knowledge of the subsurface. A major contribution comes from the observation that the contemporary stress field and the pore pressure environment in the fold belt area are non-uniform. Comprehensive analysis of high-quality LWD images through the overburden has combated uncertainties brought about by the heterogeneity in the stresses and pore pressure. These data have been especially important when updating or constraining a geomechanical model in near real-time for the purpose of providing wellbore stability and completion recommendations.
The geomechanical model unique to a particular part of the structure has been combined with finite-element modelling to help identify the optimal completion strategy for the reservoir sands in a number of wells. Recently, the near real-time geomechanical analysis has been used to quickly identify the optimal perforation direction in the reservoir in order to minimise the risk of solids production during completion.Essential data sources for the modelling include LWD images from the reservoir to confirm stress orientations and LWD density data and petrophysical analysis to accurately determine sand strength (UCS). A quick-look analysis uses the calculated UCS profile and the geomechanical model to identify, and therefore avoid perforating, any weak sections of the reservoir. Doing so hopefully mitigates the risk of solids production.
This paper outlines the workflow and displays some results from the Papuan Fold Belt area.
Dynamic column breakthrough measurements for increasing LNG production efficiency with cryogenic pressure swing adsorption
Authors: Hofman Paul , May Eric , Watson Guillaume , Graham Brendan , Trebble Mark
Published: August 2017

The use of natural gas as a primary energy source is rapidly increasing on a global scale. To economically transport natural gas over long distances and satisfy this increase in demand, efficient production of liquefied natural gas (LNG) is required. Prior to the liquefaction of natural gas to produce LNG, it is highly desirable to remove N2 and CO2 impurities from the reservoir feed gas. Typically, CO2 is removed using a water-based amine solution. The regeneration of this amine solution is both energy intensive and costly. Furthermore, the amine solutions used are undesirable from health and environmental standpoints. Nitrogen is generally not removed prior to the liquefaction and must be separated from the end-flash vapor produced with the LNG. Conventionally this requires the construction of distillation towers operating at cryogenic conditions.
In the environment of a cryogenic gas plant, adsorption-based processes for separating gases have several natural advantages over other methods. However, very little work has been done studying the efficiency of adsorption processes at the pressures and temperatures found in LNG plants. We have constructed a dynamic column breakthrough apparatus capable of measuring equilibrium adsorption and kinetics of adsorption at temperatures between 190 and 298 K and pressures to 1 MPa. This system was used to study the adsorption behaviour of N2, CO2 and CH4 on carbon molecular sieves and zeolites. This presentation will describe the measurement results and the challenges that were overcome as well as future plans to construct a larger scale apparatus.
Underwater noise impact assessment and the hearing response of marine animals
Authors: Bennett Granger , McLoughlin Jim
Published: August 2017

The ability of a marine animal to hear anthropogenic (man-made) sound underwater is affected by the animal’s auditory bandwidth and its sensitivity to sound of different frequencies within that bandwidth. Auditory bandwidths for marine animals vary from species to species and may or may not coincide with, or overlap, human auditory bandwidths. For example, turtles are not able to hear some sounds that are clearly audible to humans, while dolphins can hear sounds that are beyond the range of human hearing. Therefore, underwater noise impacts assessments for marine animals need to take into account both the spectral content of the anthropogenic noise and the auditory bandwidths of the various species under consideration. This paper demonstrates how the auditory bandwidth and sensitivity of marine animals to sounds of different frequencies can affect the outcomes of impact assessments. The analysis is supported by results from underwater noise modelling and noise measurements.
Rigless well intervention and trees on wire from a DPII vessel: a case study
Authors: Soares Rui , Thompson Steve , Smillie Robert
Published: August 2017

Since the 2006 bidding rounds, exploration activity in both the Timor-Leste exclusive offshore area (TLEA) and joint petroleum development area (JPDA) has progressed steadily.
Within the JPDA, exploration remains largely focussed in the Jurassic-age Plover and Elang Sandstone formations in the Flamingo Trough-Sahul Syncline region. Over 700 MMbbls of liquids and 4Tcf of gas have been discovered in this western region of the JPDA, including the 2008 Kitan oil field discovery by Eni, which is currently scheduled for production in 2011.
Recent seismic survey activity within the JPDA by PSC holders Petronas and Oilex has resulted in the combined acquisition of 2,800 square kilometres of new 3D data. These surveys, together with on-going re-evaluation of existing well data by these companies, has helped further refine the knowledge of petroleum systems within the JPDA, in preparation for drilling campaigns scheduled for late 2009 and early 2010.
Within the TLEA, multi-client seismic surveys undertaken in 2005, together with on-shore academic research, indicates that the prospective Mesozoic sequence of the Northern Bonaparte Basin underlies the Timor Trough, greatly enhancing the petroleum prospectivity of this region.
Further detailed 2D and 3D seismic surveys in the TLEA have been recently completed by PSC holders Reliance Exploration and Eni. The first wells to be drilled in this deeper water frontier region are scheduled for 2010.
2010 PESA industry review–exploration
Authors: Lavin Ciaran , Walker Terry , Knowles Yvette
Published: August 2017

An uncertain global economy, offset by strong commodity prices, provided the backdrop to a subdued yet solid level of exploration activity in 2010. The major loci of activity in the Australian oil and gas industry were the Exmouth Plateau, where exploration for conventional gas in support of LNG projects was the primary driver, and the Bowen/Surat Basin, where coal seam gas (CSG) for LNG was the main target.
Onshore permit awards dominated new licensing in 2010, with 31 exploration permits awarded over an area of 190,000 km2. The majority of these permits are focused on unconventional gas exploration. Conversely only 14 exploration permits (30,000 km) were awarded offshore, all in northwest Australia. This historically low level can be related to an already extensive coverage of existing permits in the offshore petroleum provinces and delays in the announcement of acreage awards from the 2009(II) acreage release.
Twenty-nine 2D seismic surveys were started in 2010, with three still active at the end of the year. Once completed, the 2010 surveys will total nearly 37,000 km of data, with 76% offshore. Twenty-one 3D seismic surveys commenced in 2010, with six still active at year end. The 2010 surveys will ultimately comprise approximately 29,000 km2 of data, with 95% offshore. Northwest Australia dominated seismic activities.
Exploration drilling for conventional hydrocarbon resources was relatively subdued in 2010, with 63 wells spudded, compared to 92 wells in 2008 and 74 in 2009. Of the 49 wildcat wells where results are known, 51% reported hydrocarbon discoveries. This was a little less than the 57% in 2009 and up on the 39% in 2008. The discoveries were distributed across most of the traditional petroleum provinces.
High levels of CSG drilling continued in 2010, exceeding 2008 activity but less than that of 2009. At least 648 CSG wells were spudded in 2010, mostly in the new heartland plays of the Bowen/Surat, Gunnedah and Clarence-Moreton basins. This compares with more than 600 CSG wells drilled in 2008 and more than 900 in 2009.
The first dedicated Australian shale gas exploration drilling took place in 2010. Emerging shale plays in the Cooper and Perth basins were tested.
The changing face of Queensland's petroleum industry
Authors: Troup Alison , Green Peter
Published: August 2017

The cycles and related changes in exploration targets identified in this study show the evolution of the Queensland petroleum industry from conventional petroleum to coal seam gas dominance. Delineation of these cycles was undertaken using petroleum exploration well data, and production and reserves statistics. Although the cycles are defined on the basis of exploration activity, there is a very different history in the types of targets and commodities explored for in the Bowen-Surat and Cooper-Eromanga basins. Trends in exploration success have been influenced by technology improvements, better understanding of target reservoirs, proximity to infrastructure, government policy and world oil prices.
Four distinct exploration cycles have been identified from the data. During the first cycle (1959–74) exploration focused predominantly on the shallower Jurassic-aged reservoirs in the Bowen-Surat basins resulting in the discovery of most of the major conventional oil and gas fields. The second cycle (1979–89) saw exploration begin in earnest in the Cooper-Eromanga basins and a switch to predominantly Triassic-aged reservoirs in the Bowen-Surat basins. The first coal seam gas exploration wells were drilled during this cycle. The third cycle (1990–99) shows a decrease in the number of conventional petroleum wells across both regions and the beginning of the switch to the present dominance of coal seam gas. The fourth cycle (2000–present) shows a significant decrease in the number of conventional exploration wells drilled across both regions, but an increase in the success rates. All conventional discoveries in the Bowen-Surat basins during cycle four have been in Permian-aged reservoirs, reflecting a change in the exploration focus to deeper parts of the Bowen Basin. Coal seam gas exploration has expanded significantly, with the Walloon Coal Measures being targeted, resulting in nearly four coal seam gas wells drilled for each conventional petroleum exploration well state-wide since 2000.
Examination of coal seam gas exploration highlights the many false starts since the first well was drilled in 1980. Exploration has shifted from area to area as companies tested different exploration concepts and completion techniques. The most obvious shift has been from Permian-aged targets of the Bowen Basin into the Jurassic-aged Walloon Coal Measures in the Surat and Clarence-Moreton basins, as its prospectivity was realised.
Continental margin compression: a comparison between compression in the Otway Basin of the southern Australian margin and the Rockall-Faroe area in the northeast Atlantic margin
Authors: Tuitt Adrian , Holford Simon , Hillis Richard , Underhill John , Ritchie Derek , Johnson Howard , Hitchen Ken , Stoker Martyn , Tassone David
Published: August 2017

There is growing recognition that many passive margins have undergone compressional deformation subsequent to continental breakup, including the southern Australian margin. This deformation commonly results in formation of domal anticlines with four-way dip closures that are attractive targets for hydrocarbon exploration, and many such structures host major hydrocarbon accumulations in the Otway and Gippsland basins; however, the driving mechanisms behind formation of these structures are not completely understood. We compare the history of post-breakup compression in the Otway Basin of the southern Australian margin, with that of the Rockall-Faroe area of the northeast Atlantic margin, which has been far more extensively studied with the aim of establishing a better understanding of the genesis and prospectivity of such structures. Both margins have experienced protracted Mesozoic rifting histories culminating in final continental separation in the Eocene, followed by distinct phases of compressional deformation and trap formation. Whilst the structural style of the anticlines in both margins is similar (mainly fault-propagation folds formed during tectonic inversion), the number, amplitude, and length of the structures in the northeast Atlantic margin are much higher than the southern Australian margin. We propose that compressional structures at both margins formed due to far-field stresses related to plate boundaries, but the magnitude of these stresses in the northeast Atlantic margin is likely to have been higher, and the strength of the lithosphere lower. In the northeast Atlantic margin, the presence of Early Cenozoic basalt lava flows may have also contributed to an increase in pore-fluid pressure in the underlying sediment making pre-existing faults more prone to reactivation.
iPOS–an integrated production operation solution for Longtom Field
Authors: Trivedi Rajesh , Biniwale Shripad , Jabur Adil
Published: August 2017

With a vision of innovation, integrity and agility, Nexus Energy began first production of Longtom field in October 2009. The Longtom gas field is located in the Gippsland Basin, offshore Victoria where the produced gas is transported to Santos’ Patricia Baleen gas processing plant. All production data is acquired by Santos with the supervisory control and data acquisition (SCADA) system. The challenge for Nexus Energy was to monitor the field remotely in the absence of a data historian and to support the operational people proactively. Data acquisition from Santos, validation, and storage in a secured centralised repository were therefore key tasks. A system was needed that would not only track accurate production volumes to meet the daily contractual quantity (DCQ) production targets but that would also be aligned with Nexus’s vision for asset optimisation.
We describe how real-time data is acquired, validated, and stored automatically in the absence of a data historian for Longtom field, and how the deployed system provides a framework for an integrated Production Operation System (iPOS). The solution uses an integrated methodology that allows effective monitoring of real-time data trends to anticipate and prevent potential well and equipment problems, thus assisting in meeting DCQ targets and providing effective analysis techniques for decision making.
Based on full workflow automation, the system is deployed for acquisition, allocation, reporting and analysis. This has increased accuracy, accountability and timely availability of quality data, which has helped Nexus improve productivity. The comprehensive reporting tool provides access to operational and production reports via email for managers, output reports in various formats for joint venture partners, and nontechnical users without direct access to the core application. A powerful surveillance tool, integrated with the operational database, provides alarms and notifications on operation issues, which helps engineers make proactive operational decisions. The framework allows a streamlined data flow for dynamic updates of well and simulation models, improving process integration and reducing the runtime cycle.
Overpressures in the central Otway Basin: the result of rapid Pliocene–Recent sedimentation?
Authors: Tassone David , Holford Simon , Tingay Mark , Tuitt Adrian , Stoker Martyn , Hillis Richard
Published: August 2017

This paper reports the first evidence for significant overpressures in the Otway Basin, southern Australia, where most previous studies have assumed near-hydrostatic pore pressures. Overpressures are observed in the Upper Cretaceous Shipwreck supersequence in several wells in the Voluta Trough, such as Bridgewater Bay–1, Normanby–1 and Callister–1. One of these wells penetrated successions of Pliocene-Recent marine clastic sediments nearly 700 m thick that were deposited rapidly in submarine channels and that were probably carved during the late-Miocene to early-Pliocene. Wireline and drilling data suggest that overpressures present in Upper Cretaceous shales and sandstones in the Belfast Mudstone and Flaxman and Waarre formations developed either due to disequilibrium compaction—where there is no evidence of hydrocarbon generation and thick Pliocene stratigraphy is present—or due to fluid expansion where there is evidence of hydrocarbon generation and the Pliocene stratigraphy is thin to absent. The two key factors that may indicate abnormal pore pressures in Upper Cretaceous sediments in the central Otway Basin are the thickness of Pliocene stratigraphy and whether or not hydrocarbons are actively generating from source rocks.
A laboratory fracture shear cell used for simulation of fracture reactivation
Authors: Asadi Mohammad Sadegh , Rasouli Vamegh
Published: August 2017

Fault reactivation is an unfavourable incident during drilling and production that may occur due to changes in situ stresses and reservoir pressure. Only a few studies, in their analyses, have included the effects of fault geometrical properties—these are important parameters controlling fault slippage and damage around it.
In this paper, the significant influence of fracture morphology on the mechanical behaviour of rock fractures was investigated through experimental studies of shearing rock fractures in the lab. The experiments carried out using a fracture shear cell (FSC): the cell that was modified by adding a number of components to an existing true triaxial stress cell (TTSC) and designing a duplex high pressure cylinder that is capable of applying large normal stresses to the sample at a constant rate. A number of artificial blocks made of mortar material were subjected to shear tests using FSC under a wide range of normal stresses and at different shearing directions. The outputs of uniaxial compressive strength and fracture shear tests in the lab were used to plot the failure envelope of the fractured rock mass and discuss the failure mechanism through shearing. Accordingly, a calibrated, numerical discrete element method (DEM) was used to simulate the shear behaviour of fractures previously tested in the lab.
The results of lab tests and DEM simulations will be presented and different failure mechanisms that are expected during shearing will be explained. The results show the significant influence of surface roughness on shear strength and extent of damage zone along the fracture. It was found that the shearing response of fractures depends on the magnitude of normal stress, which indicates the importance of having a good knowledge of in-situ stresses when modelling fault reactivation and damage near the fault zones. The results of lab experiments and numerical simulations were compared and good agreements were observed.
Smart proppant concept for monitoring hydraulic fractures
Authors: Dyskin Arcady , Pasternak Elena , Sevel Greg , Cardell-Oliver Rachel
Published: August 2017

Monitoring subsurface fluid flow is important in mapping hydraulic fractures and identifying flow channels in reservoirs. A new monitoring technique is proposed whereby fluid is injected with smart actuators capable of organising their pulses to create a combined output with a higher proportion of energy at low frequencies. Ideally, the best results occur when actuators are sequentialised so each next actuator emits its pulse immediately after the previous actuator. The low frequency energy content achieved using sequentialisation is much higher than that achieved with a random distribution of pulses, but is relatively insensitive to practical errors in scheduling and irregular attenuations of amplitudes. Simulations show that actuators can be self-organised into a sequential state by monitoring other actuators’ pulses using the algorithm presented in this paper.
Exploring New Zealand's marine territory
Authors: Uruski Chris
Published: August 2017

Around the end of the twentieth century, awareness grew that, in addition to the Taranaki Basin, other unexplored basins in New Zealand’s large exclusive economic zone (EEZ) and extended continental shelf (ECS) may contain petroleum. GNS Science initiated a program to assess the prospectivity of more than 1 million square kilometres of sedimentary basins in New Zealand’s marine territories.
The first project in 2001 acquired, with TGS-NOPEC, a 6,200 km reconnaissance 2D seismic survey in deep-water Taranaki. This showed a large Late Cretaceous delta built out into a northwest-trending basin above a thick succession of older rocks. Many deltas around the world are petroleum provinces and the new data showed that the deep-water part of Taranaki Basin may also be prospective. Since the 2001 survey a further 9,000 km of infill 2D seismic data has been acquired and exploration continues.
The New Zealand government recognised the potential of its frontier basins and, in 2005 Crown Minerals acquired a 2D survey in the East Coast Basin, North Island. This was followed by surveys in the Great South, Raukumara and Reinga basins. Petroleum Exploration Permits were awarded in most of these and licence rounds in the Northland/Reinga Basin closed recently. New data have since been acquired from the Pegasus, Great South and Canterbury basins.
The New Zealand government, through Crown Minerals, funds all or part of a survey. GNS Science interprets the new data set and the data along with reports are packaged for free dissemination prior to a licensing round. The strategy has worked well, as indicated by the entry of ExxonMobil, OMV and Petrobras into New Zealand. Anadarko, another new entry, farmed into the previously licensed Canterbury and deep-water Taranaki basins.
One of the main results of the surveys has been to show that geology and prospectivity of New Zealand’s frontier basins may be similar to eastern Australia, as older apparently unmetamophosed successions are preserved. By extrapolating from the results in the Taranaki Basin, ultimate prospectivity is likely to be a resource of some tens of billions of barrels of oil equivalent. New Zealand’s largely submerged continent may yield continent-sized resources.
The Gjøa Semi: a North Sea project relevant for Western Australia
Authors: Aas Kristian , Bjørheim Lars
Published: August 2017

Gjøa was the largest field development project in Norway in 2010. Gjøa was proven in 1989 and are now being developed together with nearby Vega satellites. The combined reserves are estiThe recent Gjøa field development in the North Sea has many features that are relevant for the oil and gas developments north of Western Australia. While the field location is not very similar to the north of Western Australia, the field development solution is very relevant. Several subsea clusters are tied back to a semi-submersible platform with export of gas and condensate via pipelines to shore.
Other aspects to the project that are relevant to Western Australia are split location engineering between Norway and India, fabrication of the hull in Korea and subsequent heavy lift transport to the assembly yard, pre-installation of the mooring system, and tow to field with ocean going tug boats.
The semi concept, which was used for the Gjøa development, is a mature technology with few technical challenges on a conceptual level. On the other hand the building of an oil and gas platform for A$2 billion has many challenges, both economical and technical, that have to be solved to have a successful project for both the client and the contractor.
Evaluation of damage mechanisms and skin factor in tight gas reservoirs
Authors: Bahrami Hassan , Rezaee Reza , Nazhat Delair , Ostojic Jakov
Published: August 2017

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques.
The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include: mechanical damage to formation rock; plugging of natural fractures by mud solid particle invasion; relative permeability reduction around wellbore as a result of filtrate invasion; liquid leak-off into the formation during fracturing operations; water blocking; skin due to wellbore breakouts; and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures.
This study represents an evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir to understand how well productivity is affected by each of the damage mechanisms, such as natural fracture plugging, mud filtrate invasion, water blocking and perforation. Furthermore, some damage prevention and productivity improvement techniques are proposed, which can help improve well productivity in tight gas reservoirs.
Floating early production systems
Authors: Marcollo Hayden , Carra Christopher
Published: August 2017

Floating early production systems (FEPS) are becoming more important to the successful exploitation of Australia's deep water oil and gas. Importantly, FEPS help oil and gas operators reduce deep water full field development risk, as uncertainty in the reservoir characteristics are reduced by obtaining dynamic data (that is, partially producing some of the reservoir). This paper will present a review of existing FEPS that are now in use or have previously been in use worldwide and will discuss where they are headed in the future. The paper focuses on:

The selection of the floating and subsea-vessel, mooring, riser, mechanical connection, etcetera;
Technology presently available; and,
Addressing the requirements in situations where new floating and subsea technology is needed.

The qualification limits of existing technology will be discussed in the context of what systems are ready and off-the-shelf for operators to make use of now. The choice of appropriate FEPS will be discussed as a function of: proximity to pipeline infrastructure, potential production rate, capability to re-inject associated gas, prevailing variation in year-round environmental conditions, waterdepth, and, geotechnical description of sea bottom. A high level conceptual case study showing typical costs for the implementation of a deep water FEPS will be presented as a way of understanding the potential upside and downside exposure for an operator considering undertaking a deep water FEPS program.
Design and selection of corrosion inhibitors for use in subsea facilities supplied by MEG regeneration systems
Authors: Charlesworth Mark , Mancuso Sebastian , Shorthouse Timothy
Published: August 2017

A significant number of the offshore gas projects planned for the North West shelf of Australia present corrosion and flow assurance challenges (paraffin wax, hydrates and scale). Temperatures at the wellhead may be as high as 140°C, which combined with carbon dioxide levels of 10–20 mol % could lead to aggressive, acidic gas corrosion of the infrastructure and pipelines. The water depth, temperature and operating conditions of these pipelines may result in hydrate formation and subsequent blockages (particularly during shutdowns).
Many of the projects have a base case specifying the use Mono Ethylene Glycol (MEG) to suppress hydrate formation in the pipelines. In the majority of these systems, the MEG is regenerated either at satellite platforms or onshore processing plants after which it is resupplied to the injection point offshore (i.e. a re-circulating glycol system). This basis of design requires a different approach towards chemical selection than a once through system due to the possible impact of the corrosion inhibitor (and other chemicals) on the glycol regeneration system. This paper details the corrosion challenges of these systems and describes the testing required to:

Develop corrosion inhibitors that will reduce the potential for severe corrosion; and,
Meet the requirements for use in re-circulating glycol systems.
Can the Asia Pacific market accomodate Australia's LNG projects?
Authors: Harris John
Published: August 2017

The portfolio of proposed Australian LNG projects continues to grow. What is the demand outlook for Asia Pacific LNG—and can it absorb the potential volume from these projects? Who are the key importers and what are the demand uncertainties within the Asia Pacific region? Can Australian LNG penetrate markets further afield?
What has driven the growth in Australian LNG projects and how many more might emerge? Where are the projects that will compete with Australian LNG? Is Australian LNG competitive relative to other supplies? Are project costs likely to increase further?
How is the LNG supply-demand balance likely to develop in the Asia Pacific during the next decade? Is there a looming surplus of LNG and, if so, what would this mean for Australia? Does the outlook presage a buyers’ market or a sellers’ market?
Will contract expiries from established LNG exporters increase supply availability in the Asia Pacific? What could this mean for oil indexation and long term LNG contracts? Could alternative pricing mechanisms evolve and will we see an increase in short and medium term supply contracts?
This paper examines the outlook for the Asia Pacific LNG market—and the growing role Australian LNG is playing in meeting demand growth. It also reviews Australia’s competitive position and considers the way in which the structure of Asia Pacific LNG contracts may evolve over time.
Unconventional gas: local supply, global implications
Authors: McMahon Craig
Published: August 2017

The sharp growth in unconventional gas production in North America has turned the gas market on its head. Unconventional gas (coal bed methane, tight gas and shale gas) is present in large volumes throughout the world—it offers the potential to continue to reshape global gas dynamics. Many expect the North America experience of sharp unconventional gas growth to be repeated elsewhere and are forecasting the perpetuation of a global gas surplus. Is this likely? We consider the impact of its development, identify some of the issues that will constrain its growth and address some of the implications for upstream suppliers, resource holders, buyers and policy makers.
No post-Conference paper or slides are available for this presentation.
Accelerating the deployment of low emission technology in Australia
Authors: Smith Susie
Published: August 2017

Transforming the way Australia produces and uses energy must be a cornerstone of a national response to addressing greenhouse gas emissions. Natural gas can deliver significant greenhouse gas emission reductions at a fraction of the cost of alternative technologies. To drive this forward, industry is looking for policy certainty and a level playing field. Furthermore, there exists the opportunity to leverage other low emission technologies from gas—for example, the integration of natural gas combined cycle generation with a solar thermal array offers an opportunity to enable the early deployment of solar thermal technology in Australia. Integration can deliver a power outcome at lower cost and with higher conversion efficiencies than an equivalent stand-alone solar thermal facility.
Aboriginal engagement: a key component of project commercial value
Authors: Jones Craig
Published: August 2017

Effective engagement with Aboriginal peoples for project access involves more than cultural understanding and settling the compensation quantum. The GLNG project involved the largest successful Aboriginal agreement-making project in Australian resources sector history. The success was based on a structured approach to Aboriginal engagement that managed project risk in relation to cost, delay and legal action as well as creating an opportunity for Aboriginal communities to create sustainable futures. Key components of the approach include:

Enhanced internal governance; and,
The recognition that project value can be created by effective risk management and non-adversarial negotiation pratices.
This paper aims to show how a commercial orientation to Aboriginal engagement, rather than a corporate social responsibility approach, can create substantial project value and deliver significant sustainability outcomes for Aboriginal communities in the project area. The paper will use the GLNG project Aboriginal engagement and agreement-making process to illustrate how enduring value can be achieved for the company and the Aboriginal communities.
Successful project delivery in complex brownfield environments
Authors: Sofra J , Stewart Andrew
Published: August 2017

Delivering services and projects in a brownfield environment has unique challenges. Brownfield, by its very nature, involves highly constrained and dynamic environments. This requires stakeholders to work collaboratively and be creative and nimble. Effective communication between client and service provider is essential. This is because the decision-making horizons are significantly shorter and consequences are more immediate. Brownfield projects are typically organised to minimise inter-discipline interfaces, with seamless delivery from engineering through to construction. Engineering effort needs to be the right sized based on the level of complexity and risk involved to ensure the effort and cost expended is appropriate for the modification or upgrade. When planning and executing brownfield projects, the following areas require special focus:

health, safety and the environment—to cope with the inherently higher risks due to live inventory, lack of space, simultaneous operations and increased personnel;
interface with operations—to plan, manage and minimise disruption to production;
live systems—to assess the impact/disruption to energised systems and coordinate tie-ins;
production—to minimise disruption and ensure that the project is executed safely while production continues;
hot work—to a minimum and where necessary contain naked flame and spark activity on site;
integrity—to ensure the condition of the asset is well understood and any sub-system upgrades to accommodate the modification are identified;
limited space—to accommodate temporary project facilities, minimising the impact on operations and maintenance activities; and,
access—to ensure that the project is planned to lessen disruption, maximise off-site preparation and to minimise on-site construction.

Systematic program management, project engineering, and a tiered engineering approach are essential to cost effective and timely delivery. For each of the eight key areas we detail some of the subtle and enabling strategies/tools that distinguish brownfield project delivery from greenfield.
The influence of an intelligent operations philosophy on design and operation of remote large-scale oil and gas developments in Australia
Authors: Cavanagh David , Westcott James
Published: August 2017

Today's large-scale oil and gas developments are often characterised by reserves in increased water depths, increased distance from shore and remoteness from existing infrastructure. The use of an intelligent operations philosophy, to create a company capability to address these challenges, has identified significant opportunities for:

Enhancing health, safety and environmental performance, reserves recovery, production performance: and,
Attracting, developing and retaining people.

To deliver these benefits, a comprehensive approach to building this "capability is required—systematically addressing people, process, organisation, physical environment and technology at each stage of the project. This paper illustrates the development of such an approach in a practical Australian context for forthcoming oil and gas developments.
Driving safety performance through behavioural change and safety leadership—an update
Authors: English Beth , Greenwood Michael
Published: August 2017

This paper describes Esso Australia's drive to further improve safety performance in its operations following a survey of 1330 employees and contractors to assess organisational culture, with a specific focus on safety. Organisational culture is widely recognised as a key element to support and sustain an effective safety culture, which in turn drives safety outcomes. The survey examined organisational, team interaction, individual and specific safety factors. Analysis of survey data and feedback obtained through focus groups involving 160 (12 %) survey respondents has identified key improvement opportunities in the areas of leadership, engagement and alignment across the organisation. A comprehensive action plan has been implemented to address the cultural elements that significantly influence safety performance.
As a response to the survey Esso has developed the Fundamentals of Safety Leadership Program to engage the hearts and minds of its workplace leaders and to provide them with knowledge, skills and confidence to effectively establish and influence stronger safer behaviours amongst the workforce. This program was completed late in 2010 with over 400 workplace leaders (employees and contractors) having attended the training, and a subsequent phase has commenced in 2011 for the entire workforce including employees and contractors (∼ 1,800 people). Key elements include the development of personal leadership credos and personal safety leadership action plans. Beyond the initial program, there will be ongoing coaching and mentoring for the workplace leadership team. The Fundamentals of Safety Program will be repeated on a five year cycle and has been included in the leader training roadmap.
The value of real consultancy
Authors: Thomas Howard
Published: August 2017

The problems of an ageing workforce and loss of corporate memory are often cited as reasons for process safety incidents and declining standards of operation. Coupled with the mobility of the Australian engineering workforce, it poses the question: how do we establish a brain trust, a source of knowledge for the benefit of the industry?
Our industry continues to operate with a silo mentality, project competing with project, concentrating on recruiting internal resources or direct hire on a contract basis to secure the resources they need. Not only is this strategy obviously failing to secure the resources, it heats the market. Furthermore, the engineers in question have little opportunity to improve their skills—even less downtime to innovate.
The potential benefit of grouping experienced and technically excellent engineers together to cross-pollinate and create original approaches to known problems is being missed. Supporting the establishment of a thriving consultancy market would enable teams of high-quality engineers to be created, adding real value to the industry as a result of the stimulation of our most knowledgeable people assets. By pooling the knowledge of our better engineers, we create the opportunity for best practice to be established and spread in our industry.
The constant drain of people leaving the industry having made their money can perhaps be stemmed if there is a prospect of stimulating and varied work. This must be a sensible course of action for a nation with huge natural resources that need to be harnessed efficiently.
Ensuring Australia's competitiveness in the global oil and gas market
Authors: Goode Peter
Published: August 2017

There is an estimated $200 billion worth of capital expenditure presently planned for Australian gas projects. These projects provide the potential for $20 billion worth of engineering and maintenance opportunities for Australian companies and an estimated 16,000 ongoing positions in the sector. The scale of these projects has drawn international attention and is increasingly drawing global competition.
Australian companies are at risk of the misperception that they don’t have the international know-how or the people to compete for these large-scale projects. We need to ensure that our Australian ingenuity and scale continue to position us as the service provider of choice for construction, project management and maintenance opportunities. Working together with industry, we have shown that we have what it takes to compete on a global scale. We also need to work with government and unions to ensure we have scalable highly-skilled people available to support these projects.
This presentation will consider the following case study: Transfield Services delivers services to companies including Woodside Energy, which operates the A$27 billion North West Shelf project, one of the world’s largest LNG production facilities with an output of 16.4 million tonnes of LNG a year. While expansion continues, ongoing brownfield project and maintenance services demand the ongoing support of a highly-skilled workforce of up to 1,000 people.
This case study explores:

innovative service solutions in a resource-scarce environment through access to global resources innovative scheduling of work; and,
the challenges of sourcing and retaining highly-skilled people by improving the opportunities for global and domestic employee mobility and investing in training and developing local people.
An institutional investor's perspective on oil and gas investment
Authors: Zhmurovsky Andy
Published: August 2017

From the perspective of an institutional oil and gas investor, investing is like creating a partnership. Given the long-term investment horizon, the focus is on creating value in the long run and on setting up the stage to withstand short-term volatility and uncertainty. A producer/developer is able to better focus on protecting its assets instead of managing the market’s expectations and quarterly earnings or KPIs. Also, projecting sub-surface performance is highly interpretive and adds another layer of risk to the already complex investment environment.
Building capabilities to deliver high well count developments
Authors: Evans Ross , Parry Stephen
Published: August 2017

In September 2008, Origin completed a $9.6 billion transaction with ConocoPhillips to form Australia Pacific LNG (APLNG)—a fifty-fifty coal seam gas to liquified natural gas joint venture. As the upstream operator, Origin is planning to ramp up production to more than five times present production levels. In a two-year period, Origin tripled Queensland CSG production volumes to 300 Tj per day. This expansion was based on existing business systems and processes and it was recognised that additional capability would be required to further ramp up production and associated activities.
A project was commissioned to build operational capability and capacity—processes, systems, organisation design and people—to efficiently drill the required number of production wells. This priority project addressed a business objective to step up the drilling of CSG production wells from approximately 60 to 350–400 per annum. The transformational solution comprised three key components: business process re-engineering, technology development, and organisational re-design. The solution included the definition, documentation and transformation of business processes—this ensured consistent, repeatable and scalable processes capable of drilling of 350–400 wells per annum.
The processes are now enabled by resource scheduling and document management systems that are fully integrated. The resultant well delivery system is managed by a team that provides the business with decision making information regarding the resource use required to support the delivery of the APLNG commitments. Given the transformational nature of the solution, the delivery of all three components was under-pinned with change management impact assessments, education, communications and deployment. The total solution was deployed in August 2010.
Oil spill preparedness and response—has the paradigm changed?
Authors: O'Driscoll Declan
Published: August 2017

Will 2010 in the future be seen as a year that marked the transformation of the approach by the oil industry to the way it manages the preparedness and response to major oil spills similar to the effect of the Exxon Valdez in 1989? The Exxon Valdez spilled 37,000 tons of crude oil in the Prince William Sound in Alaska. The spill had a profound impact on the local environment and the livelihoods of the local communities. The scale and impact of the incident led to significant regulatory changes in the United States with the introduction of the OPA 90 Act and, internationally, with the ratification and implementation of the International Convention on Oil Pollution Preparedness, Response and Cooperation (known as the OPRC Convention). The oil industry has since then undertaken many initiatives both on its own and in co-operation with governments across the world to reduce the occurrence and impact of oil spills. The positive aspect of this has been a major reduction in the number of major marine oil spills matched by increasing awareness and attention to minor oil spills. In recent years, meeting the growing demand for oil in both the developed and developing countries has led to exploration and production in ever more remote and deeper waters around the world. Has the industry adapted appropriately to the challenges of preparedness and response in these areas? The recent tragic loss of the Deepwater Horizon in the Gulf of Mexico and subsequent massive and extended oil spill raises serious questions for both industry and government. This presentation will give an overview of the developments in the approach to oil spill preparedness and response since the Exxon Valdez, the challenges the industry and government face in the region and how the oil spill in the Gulf of Mexico may change the way we manage preparedness and response in the future.
Case study of quantification of oil viscosity and saturation in complex reservoirs using advanced nuclear magnetic resonance log interpretation techniques
Authors: Manescu Adrian , Boyle Keith
Published: August 2017

In the hydrocarbon exploration process, after a prospect has been identified and an exploration well has been drilled, a critical piece of information is the oil type. Earlier wireline or while-drilling well-logging technologies provided rock properties and saturation information, but relied on expensive sampling and testing to determine oil properties.
This weakness was overcome through the introduction of nuclear magnetic resonance (NMR) logs that can provide formation properties—lithology-independent porosity, porosity distribution, permeability, etcetera—and information about the reservoir fluid viscosity.
NMR data were recently acquired in complex, high-clay content, low-salinity oil reservoirs. Traditional petrophysical interpretations throughout these reservoirs were confronted with a complex lithology—comprising feldspathic litharenites and volcanic lithic components—high clay content and low formation water salinity, of 3-4 Kppm NaCl eq.
This extended abstract shows how acquisition and interpretation of NMR data not only provided porosity and porosity distribution, but also identified oil viscosity across the logged intervals. Advanced NMR log interpretation techniques (2D-NMR maps of diffusion (D) versus T2, int) were used to identify oil NMR signal.
This technique produced a continuous profile of diffusion and intrinsic T2 distribution maps. Once the oil NMR signal was identified, an estimation of the oil viscosity was also possible because D and T2, int are related with viscosity. Several available correlations have been used and results were comparable with production data.