bluuebunny/crossref_metadata_2025 huggingface dataset:
Structural style of the White Pointer and Hammerhead Delta—deepwater fold-thrust belts, Bight Basin, Australia
Authors: MacDonald Justin , King Rosalind , Hillis Richard , Backé Guillaume
Published: August 2017

GeoScience Victoria and partners have undertaken the first detailed basin-wide study of the regional top seal in the Gippsland Basin. The Gippsland Basin is an attractive site for geological carbon storage (GCS) because of the close proximity to emission sources and the potential for large-scale storage projects. This top seal assessment involved the analysis of seal attributes (geometry, capacity and mineralogy) and empirical evidence for seal failure (soil gas geochemical anomalies, gas chimneys, hydrocarbon seepage and oil slicks). These datasets have been integrated to produce a qualitative evaluation of the containment potential for GCS, and also hydrocarbons, across the basin. Mineralogical analysis of the top seal has revealed that the Lakes Entrance Formation is principally a smectite-rich claystone. The geometry of the top seal is consistent with deposition in an early post-rift setting where marine sediments filled palaeo-topographic lows. The seal thickness and depth to seal base are greatest in the Central Deep and decrease toward the margins. There is a strong positive relationship between seal capacity column heights, seal thickness, depth to seal base and smectite content. At greater burial depths (below 700 m) and where smectite content is greater than 70%, seal capacity is increased (supportable column heights above 150 m). Natural hydrocarbon leakage and seepage onshore and offshore is correlated with fault distribution and areas of poor seal capacity. This study provides a framework for qualitatively evaluating seal potential at a basin scale. It has shown that the potential of the regional top seal over the Central Deep, Southern Terrace, central eastern Lake Wellington Depression and the southern to central near shore areas in the Seaspray Depression are most suitable for the containment of supercritical CO2. Further toward the margin of the regional seal in both onshore and offshore areas, containment of supercritical CO2 is less likely.
A novel approach in extracting predictive information from water-oil ratio for enhanced water production mechanism diagnosis
Authors: Rabiei Minou , Gupta Ritu , Cheong Yaw Peng , Soto Gerardo A. Sanchez
Published: August 2017

Despite the advances in water shutoff technologies, the lack of an efficient diagnostic technique to identify excess water production mechanisms in oil wells is preventing these technologies being applied to deliver the desired results, which costs oil companies a lot of time and money.
This paper presents a novel integrated approach for diagnosing water production mechanisms by extracting hidden predictive information from water-oil ratio (WOR) graphs and integrating it with static reservoir parameters. Two common types of excess water production mechanism (coning and channelling) were simulated where a wide range of cases were generated by varying a number of reservoir parameters. Plots of WOR against oil recovery factor were used to extract the key features of the WOR data. Tree-based ensemble classifiers were then applied to integrate these features with the reservoir parameters and build classification models for predicting the water production mechanism.
Our results show high rates of prediction accuracy for the range of WOR variables and reservoir parameters explored, which demonstrate the efficiency of the proposed ensemble classifiers. Proactive water control procedures based on proper diagnosis obtained by the proposed technique would greatly optimise oil productivity and reduce the environmental impacts of the unwanted water.
Transport and installation of 14 mooring piles at 1,300 m water depth with a DP2 heavy lift vessel
Authors: Meijer Sjoerd , Krabbendam Richard
Published: August 2017

The Kikeh field is located in water of some 1,300 meters depth, and 65 miles northwest of Labuan, offshore of Sabah (Borneo) in eastern Malaysia. The Kikeh deepwater project (Fig. 1) includes the first spar platform installation outside the Gulf of Mexico. Mooring the 16,400-tonne spar and a tender-assisted drill rig requires the presence of a mooring system comprising 14 mooring piles of different lengths and weights, the largest of which is 55 m long, has a diameter of 2.13 m and weighs 140 tonnes.
A geomechanical approach for sanding risk assessment applied to three field cases for completion optimisation
Authors: Rahman Khalil , Khaksar Abbas , Kayes Toby
Published: August 2017

Mitigation of sand production is increasingly becoming an important and challenging issue in the petroleum industry. This is because the increasing demand for oil and gas resources is forcing the industry to expand its production operations in more challenging unconsolidated reservoir rocks and depleted sandstones with more complex well completion architecture. A sand production prediction study is now often an integral part of an overall field development planning study to see if and when sand production will be an issue over the life of the field. The appropriate type of sand control measures and a cost-effective sand management strategy are adopted for the field depending on timing and the severity of predicted sand production.
This paper presents a geomechanical modelling approach that integrates production or flow tests history with information from drilling data, well logs and rock mechanics tests. The approach has been applied to three fields in the Australasia region, all with different geological settings. The studies resulted in recommendations for three different well completion and sand control approaches. This highlights that there is no unique solution for sand production problems, and that a robust geomechanical model is capable of finding a field-specific solution considering in-situ stresses, rock strength, well trajectory, reservoir depletion, drawdown and perforation strategy. The approach results in cost-effective decision making for appropriate well/perforation trajectory, completion type (e.g. cased hole, openhole or liner completion), drawdown control or delayed sand control installation. This type of timely decision making often turns what may be perceived as an economically marginal field development scenario into a profitable project.
This paper presents three case studies to provide well engineers with guidelines to understanding the principles and overall workflow involved in sand production prediction and minimisation of sand production risk by optimising completion type.
Removal of dissolved and dispersed hydrocarbons from oil and gas produced water with Macro Porous Polymer Extraction technology to reduce toxicity and allow water reuse
Authors: Meijer Dick , Madin Chris
Published: August 2017

Legislation worldwide and current technologies used in the treatment of offshore oil and gas/condensate produced water are mainly aimed at the removal of dispersed hydrocarbons (dispersed oil). From the beginning of this century, new insights in the North Sea area revealed that specific contaminants in produced water are toxic and their impact on the environment was assessed. This insight was later supported by work in the Philippines. A comparison of water with the same total organic carbon (TOC) levels showed in one case that the unknown toxic content was higher with an unexpected disastrous effect on the biocultures. Overall parameters like biological, chemical and total oxygen demand (BOD, COD and TOC) are of no value in identifying and managing the toxic content of waste and produced water streams.
New extraction based technologies such as the Macro Porous Polymer Extraction (MPPE) technology appear to remove dispersed and dissolved toxic constituents and reduce the environmental impact. Industrial applications show a >99% toxic content reduction in produced water streams.
A recent application (at Woodside Petroleum’s Pluto LNG project) is described where the ultimate reuse of produced water was as demineralised water in an LNG plant. Emerging potential is presented for floating LNG plants currently investigated in conceptual studies by the oil and gas industry. Finally, fundamental technological mechanisms are presented that are required to meet zero harmful discharge legislation.
Planning and optimisation of large, complex, low pressure gas and water gathering systems
Authors: Pearson Robert , Mackenzie Shona , Burke Lyle , Reimer Keith
Published: August 2017

Modelling low pressure gas gathering systems for unconventional gas (UCG) and coal seam gas (CSG) or coal bed methane (CBM) developments is challenged by:

the sensitivity of well performance to system back-pressure;
statistical uncertainties over well performance and areal variability in pay quality;
the rapid build-up of friction with gas velocity;
the rate of conversion from planning assumptions to real data on wells and lines;
commissioning and initial well test reliability issues;
modelling transient well performance using steady state solutions;
unpredictable peak rates and rapid initial declines from those peak rates;
well interference effects;
large development areas with multiple gathering stations;
line looping and bi-directional lines required to accommodate compressor outages; and,
new gas treatment and transmission facilities being added onto existing system during development drilling operations.
Moreover, many of these systems have multiple gas delivery points at different delivery pressures.
Similarly, low pressure water gathering, storage, processing and delivery systems involve features that are not common in conventional water injection or salt water disposal networks, such as:

large numbers of wells tied-in using lines with very low pressure ratings;
water storage ponds or tanks that may involve evaporation losses;
gravity feed or back-flow during intermittent pumping;
infield modifications to accommodate overload situations that had not gone through a formal design change process; and,
intermittent transfer operations to take advantage of reduced power costs during the night, or to avoid peak demand penalties.
This paper will look at two case histories from North America that had to address many of these problems. The objective is to capture lessons learned to assist in the challenges that we are currently facing in ramping-up CSG production in eastern Australia.
Cetaceans and the petroleum industry—coexistence or mutual exclusion?
Authors: Polglaze John
Published: August 2017

Legends, myths and plain old misinformation abound of whale migrations interrupted by international shipping, dolphin populations displaced by dredging activities, and of seismic survey campaigns resulting in disoriented, beached whales. While risks exist, in truth the Australian petroleum industry continues to demonstrate that it can successfully coexist productively alongside populations of cetacean. These whales and dolphins are seemingly able to at least tolerate, if not actually be undisturbed by, underwater noise. Other risks to cetaceans from oil and gas activities, whether actual or perceived, encompass vessel strike, turbidity plumes from dredging, port developments, underwater blasting, spills, the laying and operation of pipelines, and similar.
URS Australia’s John Polglaze is a specialist in the environmental impact evaluation of underwater noise, and has over 15 years experience in marine environmental management and impact assessment following nearly 20 years service in the Royal Australian Navy. John presents on the range of environmental impact assessment challenges for the oil and gas industry in Australian coastal and offshore regions, and effective, pragmatic solutions for demonstrating low risks to cetaceans and other sensitive marine fauna. These include the application and limitations of computer-based models to predict underwater noise and blast propagation, the development of a risk assessment framework that has proven effective with state and Commonwealth regulators, and case studies of real-life interactions between the petroleum industry and cetacean populations. In particular, he will discuss how misunderstanding and misapprehension of these complex issues unnecessarily complicates the challenges of environmental compliance.
This topic is timely, given that Australia’s rapidly increasing whale populations, coupled with the continued expansion of offshore petroleum activities, will lead to more frequent interaction between and overlap of cetaceans and oil and gas activities.
Reducing regulatory burden on the upstream petroleum sector
Authors: Livingston Peter , Hunt Rhys
Published: August 2017

On 30 April 2009, the Productivity Commission released its Review of Regulatory Burden on the Upstream Petroleum Sector. The report identified significant unnecessary costs from delays and uncertainties in obtaining approvals, duplication of compliance requirements and inconsistent administration of regulatory processes. The commission found that these burdens could be reduced through new institutional arrangements—principally the establishment of a national offshore regulator—as well as implementation of best practice regulatory principles in all jurisdictions.
On 5 August 2009, the Commonwealth Minister for Resources and Energy, the Hon Martin Ferguson AM MP, announced the Australian Government’s intention to establish a national offshore petroleum regulator in Commonwealth offshore areas, from 1 January 2012.
The Council of Australian Governments is scheduled to consider an all-of-governments’ response to the commission’s recommendations in early 2010. The paper will discuss the policy rationale for reform, the proposed reforms and how they will be implemented.
Sub-surface model predictions and regulatory requirements
Authors: Tyson Stephen
Published: August 2017

In recent years the construction of sub-surface models to understand complex systems has become almost ubiquitous. At the same time, societies have become more litigious and governments in the Asia-Pacific region have become more demanding in their technical requirements for exploration and development approvals. But most experienced geoscientists that really understand the capabilities of these models are much more sceptical about the predictive capability of reservoir modelling and acknowledge that even their best models are either highly subjective or quantified guesses.
If reservoir models provide technical justification for investment decisions or, especially in the case of CO2 sequestration, decisions that may face future litigation, then it is important to be able to quantify their capabilities and to place reasonable limits on the expectations of these models. The simple question, ‘What is a good reservoir model?’ raises many different answers from a group of geoscientists, and yet if we are not clear on what a good model is, how can we conceptualise better models as distinct from worse models? Without clear guidelines for good models it is difficult to determine who is qualified to build a model or who is qualified to audit a model. In this situation, if authorities continue to increase their demands for models to support reservoir management decisions, then many months of effort will continue to be wasted in the construction of models with no numerical validity or predictive capability.
One of the aims of this paper is to open discussion on these issues and to suggest areas where clear consensus needs to be established for the benefit of the industry, the Government and our society. Uncertainty in structural interpretation and uncertainty in deposition have a significant impact on good reservoir management for individual companies and on the wise management of national resources. The application of good modelling practices and appropriate validation by regulatory authorities is a sensible aim for our industry and one that has been overlooked for too long.
World trends and innovations in production asset management—case studies from Australia and North America
Authors: Goode Peter
Published: August 2017

Australia is transitioning to become an energy superpower—the $43 billion Gorgon LNG project and the other comparably sized projects lining up behind the Gorgon project confirm this. There are predictions that around $80 billion of CAPEX on LNG projects will be approved for expenditure for the 2010 financial year with much more to be invested in the following years. And, we are on the cusp of further coal seam gas developments in Queensland, which could see annual production rise from 130 to more than 3,000 petajoules per annum once the infrastructure is in place.
What are the skills needed to realise the true potential of these investments?
An appropriate asset management plan is key. Asset management is more than the provision of maintenance services—it is about developing a systematic approach to managing an asset during its life and achieving the outputs required by the owner of the asset.
Program and project management of brownfield capital works, maintenance services and infrastructure projects are also essential technical capabilities to help meet the demand of the burgeoning LNG and coal seam gas industries. These skills will determine who can deliver on schedule, or ahead of it.
The other key capability will be mobilising, managing and retaining people. There is speculation that the Queensland coal seam gas industry alone will generate approximately 12,000 jobs. The industry needs to be prepared to be innovative in engaging, training and upskilling people.
As the only true global resources and industrial provider in Australia, Transfield Services will share its key learnings on effectively managing assets, projects and people from its work with clients including Canada’s largest energy company, Suncor Energy.
The Gorgon Project: bringing Australia's largest single resource development to life
Authors: May Craig , Jacklin Herb
Published: August 2017

The Chevron-operated Gorgon Project is located off the northwest coast of Western Australia and encompasses a number of mega-projects including an all-subsea upstream development of the Greater Gorgon gas fields, a greenfield gas processing facility including a 15MTPA liquefied natural gas (LNG) plant and a 300TJ/d domestic gas plant, and the world’s largest commercial scale carbon dioxide injection project.
Due to its sheer size, scale and complexity, in addition to a number of unique characteristics, the Gorgon Project has required an extraordinary level of project execution planning.
One aspect is the processing plant’s location on Barrow Island—a remote Class A nature reserve. Core to the project’s planning and success is a meticulous and robust environmental management system designed to protect Barrow Island’s unique flora and fauna. This includes stringent environmental measures such as limits on worker population and movement, quarantine requirements for all personnel, and materials and work adjustments for seasonal flora and fauna life cycles.
The project’s scope of work is also being executed from three centres: LNG facilities centered in London, infrastructure centered in Perth and construction operations centered in London, Perth and Barrow Island (according to the phase and priorities of the project).
This paper explores the following factors: the remote location of the gas fields; cohabiting industry with Barrow Island; minimising environmental impacts using efficient construction management methods such as modularisation; and working together as one team across multiple locations and time zones to demonstrate how the extraordinary can be achieved.
A strategic approach to reduce climate change risks for the LNG industry
Authors: Villa Michele
Published: August 2017

The Senate rejection of the Carbon Pollution Reduction Scheme Bill 2009 (CPRS) for the second time in December 2009 caused key sections of Australia’s big business to express concern. The stalled legislation and the challenges associated with the Copenhagen Accord to deliver a clear post-2012 global climate change agreement have only fuelled uncertainty surrounding the future of climate change policy.
This uncertainty will come at a cost for the Australian LNG industry where a raft of new projects are fast approaching final investment decisions and the real impact of a carbon impost is difficult to quantify.
Despite this uncertainty, subsequent negotiations between the Government and the Opposition regarding the LNG industry, led to an amended version of the CPRS Bill. One of the amendments accepted by the Government was related to the allocation rate and states that LNG is expected to be a moderately emissions intensive trade exposed (EITE) activity and therefore eligible to receive free permits at a fixed rate per tonne of LNG produced.
Should this version of the CPRS become legislation in 2010, LNG producers will at least be able to calculate their liability under the scheme and confirm their compliance strategy.
Given the significant value at stake with existing and new investments, oil and gas businesses should act with urgency to develop strategies to respond to a carbon constrained future, irrespective of the final legislative design. Scenario planning is an important step in considering the range of regulatory outcomes—both domestic and international—that will impact on the supply and demand of carbon assets.
Extending the Exmouth Plateau post-Callovian fairway: WA-390-P phase I exploration
Authors: Smallwood John , Banfield Jon , Cox Phil , Griffin Dean , Kusumanegara Yohan , Owen Paul , Prescott Edward , Smith Jonathan , Santoni Stefano
Published: August 2017

Discovery of the Jansz-Io field in 2000 established the presence of the Jurassic W. Spectabilis fairway in the deep-water Exmouth Plateau, North Carnarvon Basin. In conjunction with the regionally prolific Triassic Mungaroo gas play, this assisted in exciting record bid levels during the 2006 Gazettal of offsetting acreage, with the award of WA-390-P to Hess for a work commitment of 3,135 km2 3D seismic data and 16 exploration wells. In the first phase of exploration the 3D acquisition was completed and four wells positioned using 2D data were drilled in 2007.
Three of these, Glencoe–1, Briseis–1 and Nimblefoot–1, were discoveries in the post-Callovian interval, with Briseis–1 encountering additional gas pay in the Triassic Mungaroo Formation. The W. Spectabilis sandstones encountered in Glencoe–1 were analogous to those encountered in the Jansz–1 discovery well, 75 km to the northeast.
These are interpreted to have been deposited in a shallow marine environment with accommodation space controlled primarily by the relict topography of the Triassic fault blocks. In contrast, Nimblefoot–1 and Briseis–1 both encountered gas pay in deep-water sandstones of Berriasian age.
These are interpreted to be delta-front turbidites sourced from the Barrow delta to the south, analogous to the Scarborough gas field, but in fault-bounded traps in which fragments of the hanging wall systems have been preserved in the degraded footwalls of major faults. Both play types are characterised by classic seismic amplitude and AVO anomalies.
New Sydney and Adelaide gas markets—what it means for producers
Authors: Hunsaker James
Published: August 2017

The introduction of the short term trading market (STTM) as the mechanism for supply of gas to both the Sydney and Adelaide markets presents a fundamental shift in the manner in which gas is provided to these markets, directionally leading to a more liquid market and increased efficiency of supply infrastructure, including potential implications for gas producers into the future.Traditionally, Sydney and Adelaide have been supplied with gas made available under long term contracts between retailers, producers and providers of gas pipeline infrastructure. The STTM has attempted to recognise the contribution and legal standing of these foundation arrangements while providing means by which an increased range of parties may offer gas directly to the market by removing the need for long term arrangements with a downstream counterparty. The ability to sell gas into these markets without having a defined downstream buyer potentially provides an additional route to market for producers.The STTM will begin operation on 4 June 2010, preceded by a trial period beginning in March 2010. This presentation will provide a description of the new market, any additional obligations for producers and, finally, an overview of opportunities the new market may provide.
Managing the deep and difficult challenges
Authors: Phelps Steve
Published: August 2017

Deep and difficult is an often-used euphemism for those petroleum objectives that are continuing to grow into an increasingly large fraction of companies’ exploration portfolios, now the easy conventionals are in their twilight years.
Based on six years of experience of such plays and prospects in the likes of Libya, Nigeria, Brazil, the Gulf of Mexico and more, the challenges may be categorised in several dimensions: capabilities for definition; operational well execution; and, the success engineering stretch (which refers to the requirement to envisage development engineering in that uncomfortable zone beyond what is currently deliverable with today’s technology).
The ability to define the deep and difficult is addressed in two ways, with the aid of example projects from Shell’s portfolio. The sub-salt seismic imaging revolution in the Gulf of Mexico of the past three years has introduced some interesting paradigm challenges regarding velocity manipulation and image integrity (consciously choosing prospects and well locations that are not on the best image). Staff competencies and the organisational behaviours required to accept such paradigm challenges are also discussed.
Operational well execution is discussed with respect to examples of well design challenges in some high cost markets and hostile borehole operating environments. It is demonstrated that ensuring objective depths are reached and gathering sufficient data in borehole evaluation programmes are frequently more difficult than planned.
It is concluded that to make the deep and difficult genuinely viable parts of your portfolio, mixing the cocktail of aspiration and stretch with equal parts of technology delivery and flawless execution needs to be in the hands of skilled bartenders.
Is LNG the panacea for Australia's natural gas?
Authors: Harris John
Published: August 2017

Australia already has abundant natural gas reserves. To what extent will LNG exports grow? What is the potential for future conventional gas discoveries? Is there a potential round of additional CBM-sourced LNG projects? Could shale gas contribute to supply?
There are already a significant number of proposed LNG projects in Australia. How many more projects might emerge to add to the current tally? In the longer term, Australia has the potential to surpass Qatar as the world’s leading LNG exporter but which markets can help Australia realise that potential? With growing Asian demand for LNG, and buyers historically accustomed to oil-linked long term contracts, the prospects for LNG appear good. But are they? To what extent can growth in Asian gas demand absorb Australian LNG, which itself has to compete with other LNG projects? If Asian demand is satiated, what are the alternative markets?
North America provides another potential outlet for Australian LNG exports, but how do the project economics stack up relative to Asia? Does South America offer market opportunities and if so can countries there absorb a meaningful volume of Australian LNG?
A detailed consideration of project costs and the outlook for gas prices in Asia and the Americas can help shed light on this question. It can also set Australia’s LNG projects in context relative to its competitors. If LNG is not the panacea for Australia’s natural gas, will alternative monetisation options emerge, and what might they be?
Resourcing the pipeline
Authors: Elliott Jody , Beeley Mike
Published: August 2017

With more than 80 major projects in planning or already underway across the Australian resource sector, demanding some 70,000 new employees, Jody Elliott, Director of Australian resource sector careers website TheResourceChannel.com.au, will provide an overview of key projects, the number of people required and the timelines for peak people demand. Industry will be challenged to consider if enough has been done to prepare the skills required to meet this demand. Jody will discuss what is currently being done by government and industry to address the skills gap and will provide her views on what still needs to be done.
Mike Beeley, CEO of Reagent Employer Marketing, will discuss why the job of engaging talent does not just belong with the HR department—it is everyone’s role in the organisation. With the demand for top mining and exploration staff about to dramatically outstrip supply, talented professionals will become far more discerning and cynical in their examination of future employers. It will not be enough to look at a few highly-scripted staff testimonials on the website, prospective staff will want to talk privately to existing company employees to see whether promises were kept and expectations met. The future of your employer brand lies in the sum of your decisions and actions as a company, not just in your HR team. The success of your operation lies in getting this balance of promise and delivery to your staff, right.
Exploiting the industry skills shortage as a competitive advantage
Authors: Tonge Piers
Published: August 2017

Developing skilled petro-technical professionals (PTPs) has the greatest lead-time of any activity that oil and gas companies undertake today. Australia could double its gas production by 2020, which would create 50,000 new jobs. This will intensify competition for skilled petrotechnical professionals, and may drive up people costs.
The market for PTPs in Australia is tight today, with active competition for technical talent between the oil and gas industry and other extractive industries. Conventional and unconventional oil and gas projects on Australia’s west and east coasts are already chasing the same, limited, talent pool. Competition for experienced PTPs will be intensified by the impending crew change, with a disproportionate number of experienced PTPs due to retire from Australia’s oil and gas industry over the next decade.
Schlumberger Business Consulting has been benchmarking the people situation in the global oil and gas industry for the past six years, and working with exploration and production companies to address it. This paper will present our analysis of the global, and Australian, situation, with quantification of the skill balance through our demand and supply model. It will also highlight specific technical skills that will be in short supply, implications of the skills shortage, as well as potential mitigations to create competitive advantage.
Producing gas from low permeability coals
Authors: Rayner Nathan , Hendrie Ross , Bowe Michael
Published: August 2017

An assessment framework for selecting optimal drilling and completion, forecasting and operating procedures in low permeability coals.
Themes covered:

low permeability coal
drilling and production alternatives;
production forecasting and operating procedures; and,
economics and technical feasibilty.
Arrow Energy Limited has been exploring for and producing from moderate to low permeability coals for over eight years, both in Australia and internationally. Arrow has developed a systematic approach to assessing the optimal drilling and completion, forecasting and operating procedures to evaluate the best appraisal and development options.
Following the confirmation that the coal resource is of low permeability (less than 5mD) the selection of the drilling and completion strategies is inter-linked with the expected production and operating procedures. This paper summarises the approach taken by each of these discipline areas and maps out the key alternatives, data requirements and selection criteria used to recommend a production pilot in a low permeability environment.
The first stage of the assessment is to review the drilling alternatives. This includes consideration of horizontal versus deviated or vertical wells, wellbore stability and solids production conditions, stimulation requirements and the production string, including artificial lift.
Production forecasting is conducted with due regard to the technical alternatives screened as part of the drilling assessment. The quality of the forecast will be determined by the available data and the use of the appropriate forecasting tools ranging from analogue assessments, simple single well modelling through to 3D reservoir modelling.
Finally, the production procedures appropriate for the well will be selected based on the well configuration and forecast deliverability as well as regional geology and geomechanics.
This framework ensures that a consistent methodology is applied for selecting well type and operations that maximises the flow potential from our low permeability coals while ensuring due consideration to economics and technical feasibility.
Characterisation of petroleum assets for portfolio management
Authors: Wahyuputro Bernardus , Begg Steve , Bethune Graeme
Published: August 2017

There is growing use of modern portfolio management methods that integrate risks, strategic goals and optimisation techniques to aid investment decision-making in the exploration and production industry. This modern approach consists of stages of analysis that include asset analysis, strategic goals definition and portfolio selection to maximise the probability of meeting the strategic goals. To date, most work in this area has focussed on the portfolio management requirements of oil and gas operators. However, the approach has the potential to help decision-making surrounding the management of the petroleum resources of a state. Specifically, we are investigating its potential to help set fiscal terms that encourage investment whilst meeting state goals. Indonesia’s petroleum resources are used to inform and provide data for the study.
This paper presents the problems identified and solutions developed in performing the first step—describing, quantifying and modelling the uncertainty in the performance of the assets that comprise the portfolio. Due to the size and heterogeneity of the portfolio, we have chosen to characterise the assets into different types, rather than model each one individually.
The main benefit of characterising the assets is to make the problem tractable, particularly when it comes to optimisation. Characterisation will also provide insight to decision-maker’s about the nature of the portfolio that may impact long-term planning and setting of targets. Whilst the approach taken is motivated by the specific needs of a nation’s portfolio, it is expected that the lessons learned will be of use to operators with similar characteristics—large, heterogeneous portfolios.
The Millungera Basin—new geoscience supporting exploration
Authors: Hutton Laurie , Fitzell Melanie , Hoffmann Kinta , Withnall Ian , Stockill Bernie , Jupp Ben , Donchak Paul
Published: August 2017

An unknown sedimentary sequence was first recorded during a Geoscience Australia/ Geological Survey of Queensland/ pmd*CRC deep seismic reflection survey in the Mount Isa Inlier and adjacent undercover terrains, during 2006/07. The sequence occurs unconformably underneath the Carpentaria Basin succession in the Julia Creek area, east of Cloncurry in north Queensland, and is named the Millungera Basin.
A section through the basin is recorded along seismic line 07GA–IG1, recorded between north of Cloncurry to east of Croydon. In this section three internal sequences are noted—with two strongly reflective units separated by a poorly reflective unit.
As well as deep crustal seismic reflection profiles, magnetotelluric profiles were collected along the same traverse. These data show a moderately conductive Millungera Basin underlying the strongly conductive Carpentaria Basin. Zones of limited reflectors beneath the basin in the seismic sections have been interpreted as granites, raising the possibility of raised geothermal gradients.
The Millungera Basin may comprise a potential geothermal target. The Millungera Basin sequence is interpreted to overlie granites. Adjacent Proterozoic granites of the Williams Batholith are known to be high heat producing granites, containing high levels of potassium thorium and uranium.
The hydrocarbon potential of the basin is similarly uncertain. Strong reflectors in the seismic sections may be coal beds. Although the depth of the basin in the seismic section is insufficient to have reached the oil window, interpretation of gravity profiles by Geoscience Australia suggest the basin deepens to the south, possibly reaching 4,000 m. If fertile beds have reached the oil window, the structurally more complex eastern side of the basin may contain petroleum traps.
The age of the rocks in the Millungera Basin is not known. Constraints from the seismic suggest between the early Mesoproterozoic and the Middle Jurassic.
Investigations into the nature of the basin are continuing. A more detailed magnetotellurc survey is being undertaken to better define the shape of the basin. In order to reliably describe the basins components, a deep drilling program is required.
Advanced wireless telemetry system for real-time surface readout during drill stem testing
Authors: Sidek Sulaiman , Thai Woo Hsuan , Jadid Maharon Bin , Venugopal Shangkar , Marimuthu Suresh , Haddad Josmar , Fink Kevin
Published: August 2017

Drill stem testing (DST) provides reservoir information that helps evaluate the potential of a new field. The data includes permeability, total skin (damage) and formation pressure, but these calculations are possible only if the build-up period is sufficiently long to attain middle time regime. The best technique for determining the length of flowing and build-up periods required is to monitor real-time bottomhole pressure (BHP) at surface.
Traditionally, BHP and temperature data have been recorded using downhole memory gauges, but the data could only be retrieved after the test had concluded and the DST bottomhole assembly (BHA) was pulled out of hole. Wireline surface read-out (SRO) was used in the next evolution of the applicable technology. This method lowered a wireline retrieval tool into the BHA during the build-up periods to retrieve real-time data from downhole gauges. This technique worked satisfactorily during build-up periods but was difficult to achieve during flowing periods, especially at high rates and with sand or solid production.
Now, a real-time downhole data acquisition solution that uses the newest generation of an acoustic wireless telemetry system has been developed. This system allows data transmission by the tubular wall using acoustic energy during flowing and build-up periods, thus providing real-time SRO throughout the test to facilitate quick decisions and troubleshooting solutions. With the acoustic wireless telemetry system, wireline intervention during DST is not required, thus eliminating inherent risks and costs of such operations.
A project undertaken by PETRONAS and a major service company using this system was successfully implemented on jack-up rigs in Malaysia. This paper discusses the challenges and step-by-step improvements made to enable these jobs to successfully meet the sought-after goals.
Dispute review boards: expensive or priceless?
Authors: McVeigh Jennifer , Walters Karen
Published: August 2017

The soft skill of dispute management is often overlooked. Our paper explores the benefits that a dispute review board can bring to a project. Traditional attempts to resolve disputes once they have arisen will be hampered by the parties’ attitudes to each other and the dispute resolver’s ability to understand the specific nature of the project.
We explore the growth in use of dispute review boards (DRB)–a small body of experts engaged at the commencement of a project, who become very familiar with the project and who can act as dispute managers. We contrast this model with traditional dispute resolution methods.
As well as exploring the benefits that a dispute review board can bring to a project, our paper also discusses the costs associated with it. The paper also discusses practical matters such as how to structure, appoint and engage with a DRB.
Turning capital project uncertainty into positive certainty by better defining manageable risk
Authors: Gray Robert
Published: August 2017

We are all stakeholders in the development of better practices to address the challenges presented by the opportunities and responsibilities that exist in our industry. Navigating the path between uncertainty and positive project outcomes can hopefully help to generate informed decisions as well as a thorough consideration of all the relevant risks. Many risk management roles have, however, tended to develop into compliance-style functions. This paper tackles the inconsistency of risk management application via a new approach, encompassing three elements: taking a new look at some fundamental concepts; making subsequent adaptations to some familiar tools; and applying these ideas to oil and gas investment projects. At the conclusion of this paper, project managers, sponsors and boards should have a new appreciation for how the industry might further improve its performance in tackling uncertainty on complex project investment decisions.
Some challenges in hydraulic fracturing of tight gas reservoirs: an experimental study
Authors: Rasouli Vamegh , Sarmadivaleh Mohammad , Nabipour Amin
Published: August 2017

Hydraulic fracturing is a technique used to enhance production from low quality oil and gas reservoirs. This approach is the key technique specifically in developing unconventional reservoirs, such as tight formations and shale gas. During its propagation, the hydraulic fracture may arrive at different interfaces. The mechanical properties and bounding quality of the interface as well as insitu stresses are among the most significant parameters that determine the interaction mechanism, i.e. whether the hydraulic fracture stops, crosses or experiences an offset upon its arrival at the interface. The interface could be a natural fracture, an interbed, layering or any other weakness feature. In addition to the interface parameters, the rock types of the two sides of the interface may affect the interaction mechanism. To study the interaction mechanism, hydraulic fracturing experiments were conducted using a true triaxial stress cell on two cube samples of 15 cm. Sample I had a sandstone block in the middle surrounded by mortar, whereas in sample II the location of mortar and tight sandstone blocks were changed. The results indicated that besides the effect of the far field stress magnitudes, the heterogeneity of the formation texture and interface properties can have a dominant effect in propagation characteristics of an induced fracture.
Non-intrusive corrosion-erosion monitoring for subsea applications
Authors: Instanes Geir , Kristiansen Sindre , Brakstad Olav
Published: August 2017

Detection and monitoring of corrosion and erosion are essential prognostic means in preserving material integrity and reducing the life-cycle cost of industrial infrastructure, ships, aircrafts, ground vehicles, pipelines, oil installations, etc. Even topside, the operating conditions can be extremely difficult, facing problems like pipe surface roughness, fluid loading, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. Deploying a monitoring system subsea makes the application even more demanding when factors such as high pressure and limited access must be taken into account. The ClampOn Corrosion-Erosion Monitor has already been successfully installed at several locations topside and is now in its final stages of the subsea development. Non-invasiveness, high repeatability and high coverage are among its advantages, making it an excellent candidate for subsea use. The technology is based on the dispersion of ultrasonic guided wave modes. By using electromagnetism these waves can be transmitted through the pipe wall without the sensor being in direct contact with the metallic surface. It is installed on the outer pipe wall to produce real-time wall thickness information, not as a spot measurement, but as a unique average path wall thickness.
Production optimisation and water control in oil/water producing wells using horizontal downhole water sink technology
Authors: Ali Fadi , Bahrami Hassan , Byfield Po Chu , Mathew Jijin
Published: August 2017

Water breakthrough and the flow of water towards the perforations of a producing well increase production operation costs and influence overall recovery efficiency. To control water production, a downhole water sink can be used in which a well is completed in both oil and water zones. Water is produced from an interval in water zone, which can result in the same pressure drop below water oil contact (WOC) as the pressure drop created by oil or gas production.
This system can reduce water production through oil zone perforations. Water produced from water zone perforations can then be injected in deeper aquifers intervals. This technology can also be implemented in horizontal and multi-lateral wells to further increase hydrocarbon recovery with fewer water problems.
This study examines the use of horizontal downhole water sink technology to increase oil recovery. Numerical simulation is performed to optimise oil production and water control in a multi-layered oil reservoir, by optimising the direction of drilling and the downhole water sink method. Different scenarios of drilling direction and horizontal down-hole water sink method are examined to identify the option that provides maximum oil recovery. The simulation results showed that drilling horizontal wells in a north–south direction resulted in higher well productivity, and that wells with significantly more water production problems can be controlled using a horizontal downhole water sink.
Effect of pressure and salinity on the performance of a gas-liquid separator—a preliminary study
Authors: Ahmed Shakil , Sanchez-Soto Gerardo , Wong Chong , Nakagawa Edson , Naser Jamal
Published: August 2017

The separation of liquid from gas during the initial stages of the separation process is very important in increasing well productivity. This is why the design of an efficient and compact gas-liquid separator has received much attention from academic researchers as well as field operators. They all state the necessity of compact design in deploying separators offshore (and potentially subsea) to enhance the recovery of gas wells. This investigation describes an experimental and computational fluid dynamics (CFD) modelling of a laboratory-scale compact gas-liquid separator designed by CSIRO. The separator consists of two concentric pipes with a swirl tube in the annular space between the pipes. The gas-liquid mixture comes from the tangential side inlet, and the system works with a combination of gravity and centrifugal forces to achieve a highly efficient gas-liquid separation. The effect of pressure and salinity on the performance of the gas-liquid CSIRO’s separation technology (CS-T) separator is investigated in this paper. The performance of the separator is visually established by observing the liquid carry over (LCO) regime in which liquid is carried out in the gas stream. The liquid and gas-flow rate at which the LCO is observed defines the upper operational range of the separator. Air-water mixture is used for both experimental and CFD investigations. The performance is evaluated at 1, 2, 5, 10 and 12 barg pressure. The upper operational range decreases with increases in pressure. For higher pressure (10 and 12 barg), the LCO curve was nearly vertical, which indicates no change in gas-flow rate with the increase in water flow rate. Salinity does not affect the performance of the CS-T separator. The CFD results are used to visualise the continuous LCO and to understand the physics and mechanism of LCO.