bluuebunny/crossref_metadata_2025 huggingface dataset:
Defining net reservoir using the dual packer wireline formation tester: a case study from the Clio, Acme, and Acme West fields
Authors: Flett Matthew , Cass Julie , Harfoushian Jack
Published: August 2017

The Clio, Acme, and Acme West gas fields lie in the WA-42-R permit in the Carnarvon Basin, offshore WA. The reservoirs at the Clio, Acme, and Acme West fields generally have excellent reservoir characteristics with multi-Darcy permeabilities. Some additional potential may occur in more marginal-quality reservoirs. To determine the potential of the marginal sands, a dual packer wireline formation tester (WFT) was used to constrain petrophysical cut-offs of the target Mungaroo and Brigadier formations, which consist of fluvial and deltaic reservoirs. A decision-based approach in the application of the dual packer WFT has allowed for systematic evaluation of the dynamic behavior of each depositional environment at proposed reservoir cut-offs, and has provided insight into the flow mechanisms controlling productivity in the near-well environment
The controls on reservoir quality between these two depositional environments are very different. The fluvial reservoirs are characterised by large ranges of permeability variation for very small changes in porosity as a function of grain-size variation. The dual packer WFT stations conducted in the Clio–3 fluvial sands demonstrate the role of entry pressure to gas charge, and allowed for the quantification of the minimum total porosity needed for net reservoir to be present in the well
The sands in the sand/shale laminae of the deltaic environment have much less reservoir quality variation than the sands in the fluvial system. Reservoir quality is controlled by the connectivity of these sands both laterally and vertically. Sand connectivity is inferred from neutron density crossover, and is tested with dual packer WFT stations at Acme West–2
The integration of data gathered at the Clio–3 and Acme West–2 dual packer WFT stations has been used to establish net-to-gross cut-offs applied to these reservoirs
Ensuring domestic supplies of natural gas for Australian businesses and households
Authors: Nelson Timothy
Published: August 2017

Australian gas markets are undergoing a substantial transformation. The development of LNG has resulted in a step-change in gas demand. The lumpy and capital-intensive nature of exporting gas has, however, shifted the natural incentives of some economic participants. These changed incentives have created some concern among large domestic industrial users of natural gas. Some domestic gas users have advocated for the reservation of gas reserves for domestic consumption. This paper assesses whether the reservation of gas is the best public policy response to the issues facing industrial users. Developing new dispersed supplies of natural gas (e.g., NSW CSG) is the most logical way to reduce pricing pressures for industrial users of natural gas. In this context, the public policy interests of domestic gas producers and consumers should be aligned. Public policy makers must remove unnecessary barriers to the exploration and production of new gas reserves. Increasing supply at a time when new LNG loads (beyond those under construction) are unlikely to materialise would alleviate any potential shortages of natural gas. At the same time, domestic suppliers of natural gas must continue to innovate to manage uncertainties on behalf of their customers. This is already occurring through the development of gas storage to manage peak loads.
CSG water: desalination and the challenge for the CSG industry—developing a holistic CSG brine management solution
Authors: Ly Lyvonne , Fergus Ian , Page Steve
Published: August 2017

The management of brine, generated from the desalination of CSG produced water, is a key challenge for the CSG industry. In many cases, the cost and technical challenges relating to the management of brine has a greater impact on the economic and technical feasibility of desalinating CSG produced water than the desalination plant itself.
The challenge is to determine the best solution for brine management, given the high salinity of the brine and limited options available for acceptable disposal. This has driven the need for more sustainable options, including using salt recovery processes to recover the salts for beneficial use. Where suitable strata can be identified, brine injection may be considered as a low life-cycle cost solution for brine disposal. CSG brine is particularly high in alkalinity, and as such, brine management options, including acid mine waste neutralisation and recovery of salts (sodium chloride [NaCl] and sodium carbonate [Na2CO3]) are possible. The latter uses selective salt crystallisation, which is generally higher in capital and operating costs, but is offset by the revenue gained from the sale of salt(s). Other brine management options include solar evaporation ponds or zero liquid discharge technology to produce a mixed salt residue that can be disposed through onsite encapsulation or landfill. The feasibility and life-cycle cost of any brine management option depends primarily on the location of CSG sites and the availability of brine management disposal/sale opportunities in reasonable proximity—this is one of the greatest challenges for managing brackish CSG produced water sources, particularly as the CSG sites are in remote inland locations. Further challenges associated with the management of salts recovered include establishing a viable commercial route for the market sale of the salts.
This peer-reviewed paper explores technical considerations, challenges and the life-cycle cost of the brine management options. The emerging trends for desalination and brine management in the CSG Industry will also be featured in this paper.
The impact of recent shipping reforms on the offshore oil and gas industry in Australia
Authors: Bosma Shane
Published: August 2017

This peer-reviewed paper focuses on the impact of recent shipping reforms on the offshore oil and gas industry in Australia. These reforms are:
the wholesale rewrite of the Navigation Act 1912 (Cth) by the Navigation Act 2012 (Cth), and the introduction of the Marine Safety (Domestic Commercial Vessels) Act 2012 (Cth);
the registration of ships in Australia and the regulation of coastal trading in Australia; and,
the regulation of marine pollution in Australia.
The regulatory framework for offshore oil and gas facilities, and the interaction between the maritime legislation and the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth)—specifically, how the legislation applies at different stages of the operation of offshore oil and gas facilities—is considered. Also considered is the Australian Government’s Stronger Shipping for a Stronger Economy shipping reform package, which aims to position the Australian shipping industry to take advantage of opportunities provided by an expanding export market.
This peer-reviewed paper also considers the new offences for oil pollution from ships, the widened scope of liability to include charterers of ships for oil pollution, and the significantly increased penalties for pollution offences promulgated by the Maritime Legislation Amendment Act 2011 (Cth).
The text was finalised in November 2012, and for that reason developments after this date have not been treated.
Blowout preventer (BOP) risk model to assist critical decisions in offshore drilling
Authors: Alme Inge , Casal Angel , Leinum Trygve , Flesland Helge
Published: August 2017

The BOP is a critical safety system of an offshore drilling rig, as shown in the 2010 Macondo accident. A challenge for the oil and gas industry is to decide what to do when the BOP is failing. Pulling the BOP to the surface during operations for inspection and testing is a costly and timely operation. Many of the potential failures are not critical to overall safety as multiple levels of redundancy are often available.
Scandpower and Moduspec, both subsidiaries of Lloyd’s Register, have developed a BOP risk model that will assist the industry make the pull or no pull decisions. Scandpower’s proprietary software RiskSpectrum is used for the modelling. This software is used for equivalent decision support in the nuclear power industry, where the risk levels of total nuclear power plants are monitored live by operators in the control rooms.
By modelling existing BOPs and their submerged control systems, and using risk monitor software for keeping track on the status of the BOP subsystems and components, the industry is able to define the real-time operational risk level the BOP is operating at. It, therefore, allows the inclusion for sensitivity modelling with possible faulty components factored in the model. The main task of the risk model is to guide and support energy companies and regulators in the decision process when considering whether to pull the BOP for repairs. Moreover, it will help the communication with the regulators, since the basis for the decisions are more traceable and easier to follow for a third party.
Measuring ultrasonic characterisation to determine the impact of TOC and the stress field on shale gas anisotropy
Authors: Altowairqi Yazeed , Rezaee Reza , Urosevic Milovan , Piane Claudio Delle
Published: August 2017

While the majority of natural gas is produced from conventional sources, there is significant growth from unconventional sources, including shale-gas reservoirs. To produce gas economically, candidate shale typically requires a range of characteristics, including a relatively high total organic carbon (TOC) content, and it must be gas mature. Mechanical and dynamic elastic properties are also important shale characteristics that are not well understood as there have been a limited number of investigations of well-preserved samples. In this study, the elastic properties of shale samples are determined by measuring wave velocities. An array of ultrasonic transducers are used to measure five independent wave velocities, which are used to calculate the elastic properties of the shale. The results indicated that for the shale examined in this research, P- and S-wave velocities vary depending on the isotropic stress conditions with respect to the fabric and TOC content. It was shown that the isotropic stress significantly impacts velocity. In addition, S-wave anisotropy was significantly affected by increasing stress anisotropy. Stress orientation, with respect to fabric orientation, was found to be an important influence on the degree of anisotropy of the dynamic elastic properties in the shale. Furthermore, the relationship between acoustic impedance (AI) and TOC was established for all the samples.
The application of downhole gas compression to improve productivity for depleted natural gas reservoirs
Authors: Mohd Ismail Mohd Dali , Hossain Mofazzal
Published: August 2017

Selection of an optimal artificial lift technology to prolong a depleted gas reservoir has always been a challenge in the oil and gas industry. To be able to have a solution that has low intervention costs and a long operating life is the key. Downhole gas compression (DGC) is the new form of artificial lift technology specifically designed, for gas wells, to increase productivity and maximise the recovery factor of the reservoir. DGC would provide a 20–40% production gain anytime during the production life-cycle of the well. Numerous challenges, however, associated with the design, development and implementation of this new technology are not well understood or documented. Thus, this study has been focused on understanding the key concepts of DGC technology and investigates its potential application for increasing the well productivity of gas wells through sensitivity studies. Emphases are given on the development of a mathematical model that can be used to investigate the effect of reservoir and well operating conditions with the production gain of DGC.
This peer-reviewed paper presents the results of some case studies, identifying the key factors associated with the operating condition, well completion, and reservoir properties considered for the successful deployment of such an alternate form of artificial lift method for a gas well based on sensitivity analysis using a developed mathematical model. The sensitivity results confirm a significant gain of well productivity using DGC for certain reservoir and operating conditions.
A glass half full analysis: lessons learnt from land access experiences for the emerging shale gas industry in Western Australia
Authors: Matthews Kate , Forge Philippa
Published: August 2017

Western Australia (WA) is on the cusp of developing shale gas. The Australian shale industry is still in its infancy, which is an opportune time to reflect on the challenges faced by its predecessors. The legacy from ongoing coal seam gas (CSG) projects, and the uncertainties associated with this emerging industry, will heighten community scrutiny and potentially require industry players and regulatory authorities to understand and work in new regulations covering this new industry. The shale industry must acknowledge and meet head on the challenges posed by this environment.
Shale gas is typically drilled and produced in a similar way to conventional natural gas reserves. As a result of shale’s low permeability, however, shale gas development also requires fracture stimulation and more closely spaced wells. For example, often six to ten wells may be concentrated on one pad. Technological advancements in gas drilling have fundamentally changed the market, making shale gas a realistic option for supplying part of future global energy requirements.
This peer-reviewed paper examines the lessons learnt from the land use conflicts associated with CSG projects in Queensland and onshore shale developments in the US. In particular, it highlights the importance of understanding the land access approval process and engaging stakeholders effectively, so as to reduce permitting and negotiation delays, which are a key risk to the commercialisation of significant shale reserves. This peer-reviewed paper also explores what approval requirements constrain the delivery of these future projects and what recommendations can be made from the Queensland and United States examples to ensure the viability of onshore shale projects in WA.
Prediction of mobile water in a tight gas sandstone reservoir using NMR and fractional flow model
Authors: Anantawati Maria , Bulgauda Suryakant
Published: August 2017

One of the objectives of petrophysical interpretation is the estimation of the respective volumes of formation fluids. With traditional interpretation using conventional openhole logs it is only possible to determine the total amount of water. The challenge is to determine the volumes of bound water (clay-bound and capillary-bound) and free water. At the moment, NMR is the only measurement that can help distinguish the volumes of each water component (clay-bound, capillary-bound and mobile), using cut-offs on T2 (transverse relaxation time). However NMR interpretation also requires information on reservoir properties. Alternatively, steady-state relative permeability and fractional flow of water can be used to determine the potential of mobile water.
The study area, located in the Cooper Basin, South Australia, is the target of a planned gas development project in the Patchawarra formation. It comprises multiple stacked fluvial sands which are heterogeneous, tight and of low deliverability. The sands are completed with multi-stage pin-point fracturing as a key enabling technology for the area.
A comprehensive set of data, including conventional logs, cores and NMR logs, were acquired. Routine and special core analysis were performed, including NMR, electrical properties, centrifuge capillary pressure, high-pressure mercury injection, and full curve steady state relative permeability. A fractional flow model was built based on core and NMR data to determine potential mobile water and the results compared with production logs.
This paper (SPE 165766) was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibition, held in Jakarta, Indonesia, from 22–24 October 2013.
Some lessons learnt from drilling a shale gas well in Western Australia
Authors: Rasouli Vamegh
Published: August 2017

The Arrowsmith–2 well is the first dedicated shale gas well in WA. The well is situated in the central eastern area of Permit EP413, with the surface location being about 30 km north of the township of Eneabba. Norwest, as the operator and on behalf of its joint venture partners, drilled the Arrowsmith–2 exploration well in mid-2011. In 2012 the well was subsequently perforated and fracture stimulated in five discrete stages across four formations: the High Cliff Sand Stone (HCSS); Irwin River Coal Measures (IRCM); Carynginia Formation; and, Kockatea Shale. The fraccing results have shown excellent rates of gas flow for the size of the intervals fracced, and have produced oil and/or condensate to surface from the two intervals flowed back.
This paper discusses some drilling operation and design aspects of Arrowsmith–2. A review of the regional geology, basic well design, and well objectives will be given. The importance of geomechanical studies for minimising wellbore-related problems during drilling and after that for hydraulic fracturing operation will be discussed, and the results of the studies undertaken presented. The wireline logging suite run in this well was used to interpret the formations’ mechanical properties. Also, laboratory tests were performed to estimate hydro-mechanical properties of the formations. The lessons from drilling this well will be used for drilling future wells in the area with the objective of saving time and costs.
Riser gas risk mitigation with advanced flow detection and managed pressure drilling technologies in deepwater operations in Australia
Authors: Toralde Julmar Shaun Sadicon , Wuest Chad Henry , DeGasperis Robert
Published: August 2017

The threat of riser gas in deepwater drilling operations is real. Studies show that gas kicks unintentionally entrained in oil-based mud in deepwater are unlikely to break out of solution until they are above the subsea blowout preventers (BOPs). The rig diverter is conventionally used to vent riser gas with minimal control and considerable risk and environmental impact involved.
Reactive riser gas systems provide a riser gas handling (RGH) joint that is composed of a retrofitted annular BOP and a flow spool with hoses installed on top of the rig marine riser. A proactive, alternative approach to riser gas handling, called riser gas risk mitigation, is proposed by using managed pressure drilling (MPD) equipment. MPD involves the use of a rotating control device (RCD) to create a closed and pressurisable drilling system where flow out of the well is diverted to an automated MPD choke manifold with a high-resolution mass flow meter that increases the sensitivity and reaction time of the system to kicks, losses and other unwanted drilling events.
Experiments and field deployments have shown that the deepwater MPD system can detect a gas influx before it dissolves in oil-based mud, allowing for management of the same using conventional well control methods. Since the MPD system has already closed the well in, automatic diversion and control of gas in the riser is also possible, if required. This paper presents experience gained from deepwater MPD operations in the Asia-Pacific to illustrate this, and possible deployment options in Australia are discussed.
Reservoir characterisation of the Patchawarra Formation within a deep, basin-margin gas accumulation
Authors: Stephens Tim , Richards Brenton , Lim Joseph
Published: August 2017

An exploration program to assess the basin-centred gas (BCG) and stratigraphic trap potential of the Mettika Embayment in the southern Cooper Basin resulted in the discovery of gas at Hornet–1 and Kingston Rule–1. The embayment is a confined fluvial sedimentary depocentre surrounded by prolific gas fields producing from structurally closed anticlines. Gas pay was identified and both wells produced sustained gas flows to surface of between 1.2 and 2.2 MMscf/d after fracture stimulation. Core collected from the Patchawarra Formation sandstone reservoir was analysed to constrain the depositional environment and establish petrophysical properties by routine and special core analysis. An integrated reservoir study was undertaken to understand depositional setting, reservoir architecture, trapping mechanisms, permeability, and saturation controls on productivity. Gas identified in the embayment appears to have accumulated in subtle stratigraphic and combination structural traps against the flanks of existing fields and does not display the geological and physical characteristics of a BCG play. The impact and analysis of hydrocarbon migration and reservoir trapping influences in this basin-margin gas accumulation may be applicable to other under-explored flank and trough plays of the Cooper Basin.
Sustaining social licence—the application of social impact assessment across the operational lifecycle
Authors: Coakes Sheridan , Lamb Karen
Published: August 2017

Most Australian resource companies, including those in the oil and gas sector, recognise that effective community engagement enhances their corporate reputation and underpins their social licence to operate. Industry-leading companies also understand the importance of assessing and managing the socio-economic impacts of their projects and operations with the same rigour as environmental, health and safety impacts. Some companies, however, fail to see the value of applying outcomes of robust socio-economic impact assessments (SEIA) to long-term business planning and performance monitoring; instead they use the approach as a one-off assessment process.
This paper discusses the value of applying SEIA to inform business planning in a company’s social and environmental functions. The methods and techniques that are presented may assist companies in:
developing an improved understanding of socially-related impacts, their significance and appropriate management strategies;documenting socio-economic contributions locally and regionally to illustrate higher order impacts and afford improved management of operational impacts;assessing community resilience, to inform, prioritise and structure community investment planning and capacity building;designing and structuring engagement to meet business objectives and reporting requirements;understanding communities, their engagement preferences, values, needs and opportunities to afford the development of more genuine relationships and partnerships; and,developing appropriate indicators to effectively monitor social impacts.
Such outputs can assist in greater efficiencies, streamlining of assessment processes and improved relationships in the long-term. Where appropriate, this paper presents case studies to illustrate the application of such techniques and their value in meeting business, government and community needs and expectations.
EPCM contracting: clearing the minefield
Authors: Whitehead Julie , Walters Karen
Published: August 2017

The past year has seen a downturn in the number of new mining and infrastructure projects in Australia. Despite that, the authors are noticing a continuation of the trend towards a greater use of engineering, procurement and construction management (EPCM) style contracting.
The increased use of EPCM contracts is in part due to projects becoming larger and more complex. As these projects can only be delivered by multiple contractors who all seek to limit their liability, the EPCM contract offers a useful framework for coordinating and managing those contractors, and maximising the owner’s recourse to them.
This is particularly so in the oil and gas industry, with many projects using this form of project delivery.
As there is no standard-form EPCM contract, however, and given the complex technical nature of these types of projects, negotiating an EPCM contract can be fraught with danger, especially for owners who may not have used this style of contract before.
This paper discusses the unique characteristics of the EPCM contract (particularly in contrast to the engineering, procurement and construction style contract), the typical risk allocation, and the creative use of compensation and incentive regimes to drive optimum performance.
The EPCM model is not suited to all projects, but if it is appropriately negotiated and drafted, and is well managed by an appropriately skilled and resourced owner’s team, it can provide a platform for excellence in project delivery.
The study of lateral variability of Kockatea Shale across the Perth Basin: an integration of electrofacies and lithofacies characteristics
Authors: Dargahi Hanieh Jafary , Rezaee Reza
Published: August 2017

The recognition of distinct rock types through log responses, referred to as electrofacies, is a fundamental role in mapping stratigraphic units that do not have any specific geological description. Lateral variability within adjoining intervals is differentiated by studying lithological characteristics such as petrography and mineralogy acquired from visual core description. In non-cored wells electrofacies analysis, therefore, is the most reliable way in determining reservoir zonations. The electrofacies’ accuracy is critically important in defining potentially desirable rock types for shale gas reservoirs in non-cored intervals, which can be obtained through an analogy of well log responses in identical lithofacies within cored wells. Considering the complexity of making a final prediction due to the unavailability of different well logs covering the whole area, only the gamma-ray log is used in determining electrofacies patterns within the studied shale gas intervals. The electrofacies patterns within identified lithofacies have been studied for the Kockatea Shale, which presented analogous patterns for identical lithological facies. The similarity has allowed for the correlation of lithofacies in cored and non-cored wells, and the evaluation of lithofacies variability and development within various wells. The correlation of the defined electrofacies indicates facies changes across the basin in association with thickening of some lithofacies. The thickest part of the electrofacies is shown at the Dandaragan Trough and the Beagle Ridge. Some electrofacies, however, have disappeared in some parts of these areas, such as lithofacies E in the Beagle Ridge, which is partially replaced by electrofacies C.
Gigacell grids: indulgence or necessity
Authors: Tyson Stephen
Published: August 2017

Upscaling techniques developed in the late 1980s continue to form the basis of including detailed geological data in flow simulation models. While these techniques are theoretically robust, in practice the process of upscaling has variable success and the concept of replacing a complex and detailed geological model with an array of effective properties is considered to be a source of error in the construction of simulation models. The default ratio between the geological grid and the simulation grid in popular geological modelling programs is eight fine cells to one coarse cell. Examination of the number of samples required to estimate the mean value of a population suggest that this ratio should be much higher, and that more accurate upscaling results would be obtained if there were 1,000 fine cells in each coarse cell. This suggests that a simulation grid of 500,000 cells should have a corresponding geological grid with 500 million cells to improve the accuracy of the computation of effective properties. This is beyond the capabilities of the present generation of commercial geological modelling software used in the petroleum industry. This paper discusses the creation of gigacell grids, and the ease of construction and difficulties in population using existing geostatistical algorithms.
Increased safety and improved operation of pipelines with integrated condition sensing in flexible risers and flowlines
Authors: Andersen Bo A.
Published: August 2017

Continuous condition monitoring of offshore production installations is a vital part of integrity management to ensure safe operation of the asset at its optimum level for the maximum period of time. The recent implementation of fiber-optic condition monitoring embedded into the structures of flexible risers and flowlines is an important step towards turning flexible pipelines into inspectable structures. Embedded sensors enable a suite of monitoring options for both real-time response and long-term changes, which can provide a highly accurate picture of a pipeline’s condition during operation.
In this paper the author reports the results from extensive full-scale testing on flexible pipes instrumented with sensors, conducted in cooperation with a major operator. The testing includes detection of a breach of the outer sheath with ingress of seawater into the annulus, remote monitoring of the location of accessories mounted on the pipe—such as buoyancy modules—monitoring of the temperature at a buried section of a pipe in the seabed, identification of hotspots, detection of breaks of tensile armor wires, and monitoring of accumulated fatigue damage in tensile armor wires during operation. Reported failure modes from flexible pipes in operation are briefly discussed to show that the major failure modes reported across all operators through the years are covered by the NOV integrated sensing systems.
The detection of structural and temperature issues with integrated condition sensing in flexible pipelines will allow operators to satisfy requirements for periodic inspection, which for rigid steel pipes is performed with intelligent pigging.
Environmentally acceptable surfactants applied for water-based paraffin control—novel technologies sustaining production of challenging Australian crudes
Authors: Backus Farrell , Oschmann Hans , Gunn Mike , Harvey Evan
Published: August 2017

The use of environmentally acceptable surfactants in water-based products—as opposed to hydrocarbon-based products—offers significant benefits both from an environmental and performance perspective.
Water, being a polar solvent, has a very limited capacity to dissolve non-polar hydrocarbons; however, a new generation of environmentally acceptable, novel surfactants has allowed the development of water-based wax removal technology that effectively penetrates layers of waxy deposits, and dissolves and disperses the removed paraffin. A conspicuous property of this new water-based paraffin remover is its ability (similar to some corrosion inhibitors) to migrate over surfaces resulting in the treatment of deposits not originally wetted by the product.
The continuous application of environmentally acceptable surfactants in multiphase transport systems has not only prevented paraffin deposit formation but also has allowed for the removal of persistent paraffin deposits. These new chemistries have had excellent success in many areas, including Australian production fields. Cooper Basin field studies have shown that the application of these surfactants have significantly increased production through reduced downtime during winter months where high wax content producing wells traditionally would shut down due to flow line restrictions.
This paper will review the selection and the application of these new surfactants in two Australian field locations.
Developing a new laboratory-scale drilling simulator to optimise rock drilling at Curtin University
Authors: Joodi Bahman , Brady Shaun , Richards Aaron , Rasouli Vamegh
Published: August 2017

A new simulator that has been designed and built at Curtin University can simulate rock drilling in different environments. Horizontal and vertical stresses, pore pressure, circulation pressure, rate of penetration, depth of cut, and torque can be precisely monitored by the simulator to investigate the effects of each of the parameters for optimisation purposes. A computer simulation is also initiated using Particle Flow Code in two dimensions (PFC2D) for further studies on rock cutting mechanism and direct numerical results. The results obtained by combining these two methods are of high reliability for predicting cutting behaviour of different bits.
This paper presents the new drilling equipment and the results of studies on sandstone drilling. Previously, the single cutter scratching test on Mountain Gold sandstone was modelled by PFC2D and the results were very similar to the experimental results. Here, custom-made full-face PDC bits are used for drilling in cubical samples of synthetic sandstones with known properties. Water is used as the drilling fluid and the rock sample is drilled under atmospheric conditions. Bit torque, WOB and ROP are monitored to obtain optimum drilling response in terms of ROP and specific energy.
The obtained results are of high importance in predicting drilling speed and optimum drilling parameters. This can improve well planning and has the potential to reduce the cost of drilling wells.
Modelling of external filter cake profile along the well during drilling
Authors: Kalantariasl Azim , Zeinijahromi Abbas , Bedrikovetsky Pavel
Published: August 2017

This paper presents a new mathematical model to predict the steady-state external filter cake thickness distribution and velocity profile along the wellbore during overbalanced drilling. Several models have been suggested for the prediction of external cake thickness using the force balance method. Yet, a comprehensive literature survey reveals that electrostatic forces and the permeate force correction factor have been neglected, while both can significantly change the conditions of particle detachment from the cake surface. Torque balance of hydrodynamic (lifting, tangential and permeate drag), gravity and electrostatic (DLVO) forces along with Darcy’s law and material balance is used to investigate the conditions of particle attachment/detachment on the cake surface. The results show strong effects of mud chemistry, particle size, cake permeability, tangential flow velocity, overbalance pressure, and Young’s modulus on the external filter cake thickness and velocity profile. The mathematical model can be applied as a predictive tool for the estimation of filter cake thickness. It allows for the calculation of external filter cake distribution using the physiochemical properties of mud and particles.
Coiled tubing drilling for unconventional reservoirs: the importance of cuttings transport in directional drilling
Authors: Kamyab Mohammadreza , Chin Nelson , Rasouli Vamegh , Soe Soren , Mandal Swapan
Published: August 2017

Coiled tubing (CT) technology has long been used in the oil and gas industry for workover and stimulation applications; however, the application of this technology for drilling operations has also been used more recently. Faster tripping, less operational time, continuous and safer operation, and the requirement for fewer crew members are some of the advantages that make CT a good technique for drilling specially deviated wells, in particular, in unconventional reservoirs for the purpose of improved recovery. Cuttings transport in deviated and horizontal wells is one of the challenges in directional drilling as it is influenced by different parameters including fluid velocity, density and rheological properties, as well as hole deviation angle, annulus geometry and particle sizes. To understand the transportation of the cuttings in the annulus space, therefore, it is useful to perform physical simulations. In this study the effect of wellbore angle and fluid rheological properties were investigated physically using a flow loop that has been developed recently for this purpose. The minimum transportation velocity was measured at different angles and an analysis was performed to study the fluid carrying capacity and hole cleaning efficiency. The results indicated how the change in wellbore angle could change the cuttings transport efficiency.
Productivity decline in a Salamander geothermal well: experiment, modelling and case study
Authors: You Zhenjiang , Badalyan Alexander , Bedrikovetsky Pavel , Hand Martin , Matthews Chris
Published: August 2017

Substantial formation damage and productivity decline have been observed in numerous geothermal fields. Comprehensive analysis of formation damage and prediction of productivity specifically for geothermal reservoirs, however, are not available in the literature. On the basis of laboratory study and mathematical modelling, the present work is focused on the analysis of formation damage mechanism to diagnose and predict the productivity decline.
A case study of a typical Australian geothermal reservoir (Salamander field) is performed. In this case, fines migration is recognised as the most likely candidate of all formation damage mechanisms. The attaching electrostatic forces are weak at high temperatures if compared with drag and lifting forces, which detach the particles from rock surfaces. Mobilisation of lifted fines results in particle straining in thin pore throats preferentially near the well, causing severe permeability and well productivity decline. A new model based on laboratory study is developed and field production data are successfully treated by the model.
The potential for fines migration and induced formation damage in geothermal wells is significantly higher than that for conventional oil and gas wells due to the weakening of attaching electrostatic forces under high temperatures. The evaluated well index from field data is in good agreement with mathematical modelling prediction.
The proposed model allows for long-term productivity prediction from a short production period, which allows recommending methods of skin prevention, mitigation and removal. The model is also applicable to shale, CBM, and tight oil and gas reservoirs.
2014 Offshore Petroleum Exploration Acreage Release
Authors: Constable Tania
Published: August 2017

The potential for natural gas to fuel economic growth around the world is tremendous. Australia has a pivotal role to play with our abundant natural gas reserves and record levels of investment in LNG production capacity. Australia is presently the world’s third-largest exporter of LNG, with an export capacity of 24.3 million tonnes per annum (mtpa) from three operational projects. Capacity will increase to around 90 mtpa by 2018, once the seven projects being constructed come online.
The Australian Government is committed to ensuring the long-term growth of the petroleum industry, and the promotion of competitive, sustainable and well-regulated markets operating in the best interests of the nation.
Exploration is essential for the future of Australia’s resources sector to enhance our international competitiveness while maintaining Australian energy security and that of our energy trading partners. Investment in offshore petroleum exploration is facilitated though the annual Offshore Petroleum Exploration Acreage Release prepared by the Australian Government Department of Industry and Geoscience Australia. The Offshore Petroleum Exploration Acreage Release is underpinned by a stable economic environment and clear regulatory framework that provides investment certainty and security of title.
This paper provides details about the acreage included in the 2014 Offshore Petroleum Exploration Acreage Release. All areas are supported by geological data and analysis from Geoscience Australia. This paper also discusses the introduction of cash bidding for mature areas and areas containing known petroleum accumulations, in addition to Australian Government initiatives in the offshore petroleum sphere.
The times they are a-changin': Australian biozones, petroleum basins, and the international geologic time scale (GTS) 2012
Authors: Smith Tegan , Laurie John , Hall Lisa , Nicoll Robert , Kelman Andrew , Ogg James
Published: August 2017

The international Geologic Time Scale (GTS) continually evolves due to refinements in age dating and the addition of more defined stages. The GTS 2012 has replaced GTS 2004 as the global standard timescale, resulting in changes to the age and duration of most chronological stages. These revisions have implications for interpreted ages and durations of sedimentary rocks in Australian basins, with ramifications for petroleum systems modelling. Accurate stratigraphic ages are required to reliably model the burial history of a basin, hence kerogen maturation and hydrocarbon expulsion and migration. When the resolution of the time scale is increased, models that utilise updated ages will better reflect the true basin history. The international GTS is largely built around northern hemisphere datasets. At APPEA 2009, Laurie et al. announced a program to tie Australian biozones to GTS 2004. Now, with the implementation of GTS 2012, these ties are being updated and refined, requiring a comprehensive review of the correlations between Australian and International biozonation schemes. The use of Geoscience Australia’s Timescales Database and a customised ‘Australian Datapack’ for the visualisation software package TimeScale Creator has greatly facilitated the transition from GTS 2004 to GTS 2012, as anticipated in the design of the program in 2009. Geoscience Australia’s basin biozonation and stratigraphy charts (e.g. Northern Carnarvon and Browse basins) are being reproduced to reflect the GTS 2012 and modified stratigraphic ages. Additionally, new charts are being added to the series, including a set of onshore basin charts, such as the Georgina and Canning basins.
Shell Australia—preparing to operate prelude FLNG
Authors: Marshall Jim , Grose Ian
Published: August 2017

Shell’s first floating LNG project is now well advanced and being constructed across global locations. As the steel and equipment comes together to form what will be the biggest floating facility built, Shell Australia is gearing up for the operation of Prelude FLNG. This extended abstract discusses the construction so far, including sharing imagery of the substructure and topsides in the Samsung Heavy Industries Yard in Geoje, South Korea. The progress on the world’s largest turret in Dubai and the final testing of subsea infrastructure in Malaysia are also covered. The challenges faced by Shell Australia in preparing for operations as the facility comes to life are also discussed. The business is working to build the right facilities, workforce, systems, and operations and maintenance capabilities to ensure that when the facility is towed and commissioned in a number of years, Shell Australia is ready to operate it to world-class standards for safety, reliability, and availability.
A network-centric approach to managing risk
Authors: Hankinson Bruce
Published: August 2017

The strategies of many large organisations are underpinned by top down, hierarchical management, complex forecasting and predictive modelling, standardised processes, siloed business units, division of labour, information biases and disjointed stakeholder management. Rigid and inflexible, organisations are struggling to respond to the risks associated with unpredictable, ever changing and complex operational environments.
Budget blowouts into the billions of dollars, stretched resources, increasing governance, social and political interdependencies and a complex playing field that is constantly changing as it grows and matures is what oil and gas companies in Australia today face. Proponents of Australia’s massive LNG boom are doing the hard yards and they are feeling the pressure.
Unfortunately with pressure comes poor decision making. Lack of access to evidence based and up to date, real time information means decisions are often made based on intuition or unqualified, out of date information due to immature systems. Research has clearly proven that intuitive decision making results in cognitive biases. These biases results in perceptual blindness or distortion (seeing things that aren’t really there), illogical interpretation (being non-sensical) and inaccurate judgments (being just plain wrong). Without a system in place to manage risks in it’s operational space, companies will continue to make poor decisions that only increase the risks they try so hard to control.
This paper proposes a new approach to better understanding organisational interdependency and risk management through adoption of a network centric approach. It explores the benefits of a network centric approach and how this it can be applied in a multi dimensional environment to not only reduce risk events and costs but enable a truly resilient and competitive business.
Introduction to automated health and safety risk identification and classification
Authors: Steeman Joris
Published: August 2017

During the past decade, the major oil and gas players in Australia have put in significant effort to improve their performance on health and safety. With a strong focus on safety awareness of the workforce, the Australian oil and gas industry has been able to improve their health and safety performance, with leading indicators dropping significantly. From an international perspective, however, the total recordable injury rate in Australia is still more than two and half times higher than the total recordable injury rate among member of the International Oil and Gas Producers Association.
This extended abstract introduces a new method to identifying and classifying risk and risk levels within oil and gas exploration and production operations based on the results from a trial project at an Australian LNG producer. This risk identification should be done in addition to the existing health and safety approaches. Nowadays, the workers in oil and gas operations use computer systems for managing their work, from isolations and permits to job hazard analyses. The equipment used in oil and gas exploration and production is producing large volumes of data. And external sources of information, such as the BoM, provide context on the conditions in which work is performed. Bringing these sources of data together and using automated statistical tools to identify and classify risk created a new perspective on the risk profile of activities of oil and gas operations. This enables organisations to pinpoint their risk-mitigation strategies where it will really make a difference.
Floating Super Pallet (FSP): a smart piggy back solution
Authors: Seij Michel
Published: August 2017

The FSP is Dockwise’s new transport equipment specially developed for modular transport. With a lot of development in modular build LNG plants, this is Dockwise’s answer to deal with industry demands. Using the FSP as intermediate transport medium, a œconventional transport is transformed into a piggyback transport able to deal with operational constraints and introduce logistical flexibility. The FSP’s dimensions are 60 m x 40 m x 6 m making it suitable to transport modules of 50–6,000 tons. These dimensions make these pallets perfectly fit closed stern heavy transport vessels (HTV). LNG plants are often constructed at remote locations that are restricted by shallow water and underdeveloped Material Offloading Facilities (MOF). The construction costs for a MOF to receive full size HTVs are often high. Using an FSP as intermediate medium deals with these limitation due to its maximum draft of 5 m. A conventional module transport consists of loading (roll-on, RO), voyage and discharge (roll-off [RO]). In the piggyback variant, a float-on and float-off (FLO-FLO) is added to this transport cycle. Although this introduces an extra operation, the actual transport vessel is not yet required at site during loading, seafastening, quarantining. Furthermore, introducing flexibility during the RO-RO operation, where sets of FSPs are available while the vessel is at sea with another set. In addition, this largely reduces vessel waiting time to improve the overall vessel use and minimise demurrage. It opens the way forward for novel contracting environments for module logistics.