bluuebunny/crossref_metadata_2025 huggingface dataset:
Big data analytics—lessons learnt from global E&P operators
Authors: Kalish Kevin
Published: August 2017

Exploration and production operators are striving to attain the hidden knowledge in their key asset: data.
Data and real-time data from intelligent wells supplement historical interpretations and generated datasets. It is paramount to gain insight from these multiple datasets, which enable engineers and stakeholders to make faster and more accurate decisions under uncertainty. By combining the traditional deterministic and interpretive workflows with a data-driven probabilistic set of analyses, it is possible to predict events that result in poor reservoir or well performance or facility failures.
By building predictive models based on cleansed historical data and by analysing them in real-time data streams, it is now feasible to optimise production.
Controlling costs and ensuring efficient processes that impact positively on health, safety and environment and resource usage are key benefits that fall out of analytical methodologies.
This extended abstract provides recent examples of global exploration and production operators using an analytics oilfield framework to:
improve the quality of data by integrating relevant sources from multiple monitoring and surveillance systems across all geology, geophysics and reservoir engineering (GGRE) disciplines into a unified view;
predict unplanned events so that mitigation can be planned in advance;
use predictive models to avoid frequent and unnecessary preventive maintenance that interferes with production schedules, strains maintenance staff and increases costs; and,
increase decision support across disparate upstream disciplines by using data mining to create accurate predictive and descriptive models.
The impact of RFID on the supply chain for engineering shutdowns
Authors: Lantu Maria
Published: August 2017

Shutdown activity is heavily reliant on supply chain functions, yet planning is frequently based on incorrect or incomplete information. The flow of materials and equipment is critical to preserving the schedule and budget; however, in most projects, the location of critical materials is manually tracked using spreadsheets or relies on limited enterprise resource planning (ERP) system functionality. This creates a number of problems, as there is no automated or accurate method of locating or ensuring material is available after it has left the manufacturer/supply base and is issued for installation; for example:
Recent analysis showed 50–70% of materials are subject to some type of waste (rework, wait time, transport and over processing).
Additional resources are required to manage constantly changing shutdown schedules and chase up material locations for job-card staging.
Materials expedite costs for a four-week shutdown in a remote area can exceed up to $250,000 a week.
Up to 30% of materials sent for a shutdown can be returned to inventory, which increases transport and labour costs.

This extended abstract outlines the use of radio frequency identification (RFID) technology and lean supply chain techniques for improving plant shutdown performance, following two major Brownfield engineering projects that used technology innovations, such as active RFID tags, cloud software, solar energy, GPS, 3G/wireless network and mobile devices.
RFID real-time location material tracking and LEAN principles were applied to critical materials to remove waste from shutdown processes, protect the integrity of the shutdown plan and help reduce costs by up to 14%.
Time-lapse seismic monitoring methodologies applied to the Pyrenees Field, offshore Western Australia
Authors: Meza Ramses , Duncan Guy , Kostas Konstantinos , Kuzmin Stanislav , Florez Mauricio , Perrett Tom , Stewart James
Published: August 2017

Time-lapse dedicated 3D seismic surveys were acquired across the Pyrenees oil and gas field, Exmouth Sub-basin to map production-induced changes in the reservoir. Rock-physics 4D modelling showed that changes in pore pressure and fluid saturation would produce a time-lapse seismic response of sufficient magnitude, in both amplitude and velocity, to overcome time-lapse noise.
The dominant observed effect is associated with gas coming out of solution. The reservoir simulation model forecasted that reservoir depletion would cause gas breakout that would impact the elastic properties of the reservoir. The effect of gas breakout can be clearly observed on the 4D seismic data as a change in both amplitude and velocity. The analysis of the seismic datasets was proven to be enhanced significantly by using inversion methodologies. These included a band-limited extended-elastic impedance (EEI) approach, as well as simultaneous 4D elastic inversion. These datasets, combined with rock physics modelling, enabled quantitative interpretation of the change in 4D seismic response which was a key tool for assisting with the infill well placement and field development strategy.
The relative attractiveness of US LNG exports—is the threat to Australian projects real?
Authors: Chandra Vivek
Published: August 2017

The competitiveness of Australian LNG projects against US projects has been a subject of much debate; however, as oil prices have fallen since mid-2014, the debate has shifted from the relative commercial terms of the LNG sales contracts to the relative cost of supply. Falling oil prices have decreased the price of LNG in the traditionally oil-linked price markets of Asia. A lower cost of LNG will increase the demand for gas, especially in the power generation sector. New gas supplies would be required to meet increased demand, but the new supply must be at a competitive cost. The market price will be set by the marginal cost of incremental supply. Legacy projects in Southeast Asia, the Middle East and Australia are unable to increase their volumes. The only other source of incremental supply that can profitably sell at these lower prices are new projects in the US Gulf Coast. Australian greenfield projects will not be able to sell at these prices as they suffer from high capital expenditure (capex), high feed gas prices and high operating costs. In contrast, US Gulf Coast LNG projects are being constructed at significantly lower unit costs, have access to massive low-cost shale gas volumes and will operate at low costs using standard technology. These projects are ideally placed to operate in the lower priced environment, irrespective of the LNG sales contracts’ commercial terms.
Exposure to weather risk: a new information paradigm
Authors: Farr David , Tupper Andrew
Published: August 2017

When forecasting the weather, simple outcome statements do not always adequately describe what could eventuate for a particular location.
Importantly, some weather situations are finely balanced, and cannot be forecast five days in advance; sometimes forecasting 24 hours ahead is difficult, particularly if tropical cyclones are present.
To address these weather forecasting complexities, the Bureau of Meteorology is moving towards providing more probability based guidance, such as more information on potential rainfall ranges, wind speed probabilities, wave height probabilities, tropical cyclone formation risk and potential tropical cyclone tracks.
For response planning purposes these changes will bring their own challenges. For example, previous chances of a tropical cyclone impact have been described with yes or no forecasts. In the future these risks could be described in percentages. Responding to a 5% risk suggests that 19 out of 20 responses could be perceived to be unnecessary, while on the other hand not responding to a 5% risk could be assessed as dangerous.
Developing these new information types is only part of the process. To achieve better practice, it will also be critical to create presentation strategies that express the content in a usable manner, work with clients so they gain maximum benefit from the guidance, and enable clients to develop response plans that are aligned with the forecasts.
The Bureau of Meteorology is seeking to work in a closer partnership with the resource sector on this to help maximise operational efficiencies, while ensuring a safe working environment.
Australian oil and gas: maximising inbound investments—tax risks and opportunities
Authors: Townsend Belinda
Published: August 2017

The ability for Australia to attract and retain foreign capital is crucial to the continued expansion and long-term development and sustainability of Australia’s oil and gas industry.
A well-known and accepted competitive advantage, which facilitates inbound investment into the Australian oil and gas industry, is the stability of Australia’s tax and regulatory system. Having said this, inbound investors are faced with numerous challenges in seeking to navigate and understand Australian tax issues associated with not only ensuring the successful completion of a transaction but to also manage their ongoing after-tax return on investment.
These investors are exposed to Australia’s complex international tax landscape, given the level of cross-border investment, financing, profit repatriation, transfer pricing and exit/sell down issues.
The key is for inbound investors to understand, monitor and pro-actively manage their international tax affairs as efficiently and effectively as possible.
This extended abstract is targeted on assisting inbound investors to understand key considerations associated with investment ownership in the Australian oil and gas industry, and to assist those investors in making strategic investment decisions and to better understand tax risks and opportunities. The topics covered will include:

Key tax drivers and considerations associated with executing transactions successfully.
Structuring inbound oil and gas investments into Australia.
Investment funding and profit repatriation strategies.
Transfer pricing and related company transactions.
Exit and sell down strategies.
Getting the message across—taxation contribution of the petroleum industry in Australia
Authors: Franchina Carlo , Henderson Rod , Nand Praneel
Published: August 2017

With the global move towards tax transparency reporting measures, resource companies face challenges in ensuring that reporting captures the full extent of revenues contributed by resource companies and also correctly reports the project and profitability life cycles of resource companies.
This extended abstract focuses on the global tax transparency debate and highlights the challenges for large Australian and global oil and gas businesses in demonstrating their payment of their fair share of tax and contributing to the communities in which they operate. Issues to be covered include:

A summary of the revenue contribution of oil and gas companies in Australia through the layers of taxation, such as state royalties, the Petroleum Resource Rent Tax (PRRT) and corporate income taxes.
Highlighting the types and rates of taxes paid by Australian oil and gas companies compared to other selected countries.
A comparison of the concessions granted to Australian oil and gas companies to other countries.
A historical summary of taxes paid by Australian oil and gas companies.
A summary of existing and developing transparency reporting, such as the Australian Taxation Office (ATO) reporting of taxpayers with revenues more than A$100 million, the Extractive Industries Transparency Initiative, Dodd Frank rules, OECD country-by-country reporting, and BEPS developments.
Recommendations to get the message across; that is, what should be the common ground on reporting the actual overall global tax liability including income tax, resource taxes, employment taxes and indirect taxes.
Driving superior returns through strategic alignment in oil and gas
Authors: Guthridge Matt , Miller Jason
Published: August 2017

In the past decade, Australia has enjoyed significant investment in its LNG, gas and oil projects, with the combined value of projects at the publicly announced stage totalling A$197 billion. The cost of developing new LNG, gas and oil projects has escalated in the past 10 years, making Australia less competitive with locations such as North America and East Africa.
The higher costs mean that many proposed projects, especially greenfield developments, will not reach a final investment decision. In this constrained investment environment, it is important for oil and gas companies to execute strategies that earn a strong return on the capital they employ.
More than 200 Australian and Asian energy and resources executives were asked to rate their company’s strategic execution capability; this revealed that oil and gas companies that have strategically-aligned operating models earn higher returns on capital employed (ROCE). It was found that while 79% of respondents believe their organisations have the correct strategy in place, only 55% believe their organisation is executing their strategy well now.
The research revealed that highly aligned oil and gas organisations are three times more likely to be executing successfully than their less aligned peers. Overall, the results imply that top teams who clearly align behind a strategy and successfully translate its intent throughout their organisations make better use of their invested capital.
The level of strategic alignment is a key question for both oil and gas investors and company executives.
Geomechanic models using finite element methods show how Cooper Basin structure and sand body geometry impacts stress variation and hydraulic fracturing results
Authors: Ditty Nicole , Cooke Dennis
Published: August 2017

Unconventional reservoirs such as tight sands and shales require hydraulic fracture stimulation to improve productivity. The success of reservoir stimulation is controlled by the local stress field but decisions are often made knowing only the average stress field.
This study uses geomechanical modelling to help explain lateral stress variability using structural geology, lithology contrast and boundary conditions. Changes in vertical and horizontal stresses are related to depth, lithology and structural position, yet these effects are not always accounted for. This is evident in the Cooper Basin, Australia, where, for example, unexpected changes in minifrac pressure are commonly observed in adjacent wells in a field. This study presents results from conceptual geomechanical models to help explain such variations in stress.
Model scenarios are constructed using finite element package to investigate the impact of structural position, rock mechanical properties and stress regime on the patterns of horizontal and vertical stress magnitudes in a layered antiform sequence. Key findings suggest that:

stress magnitude is affected by structural positioning;
different patterns of stress exist across different lithologies; and,
stress regime impacts on patterns of stress, especially in combination with curvature of structures.

These challenge traditional methods of one-dimensional mechanical earth models and show that, rather than employing methods developed for simple layer-cake geology in extensional basins, geomechanical models should be constructed in two- or even three-dimensions. Results of this study highlight part of the solution to the unconventional resource potential of the Cooper Basin. Improved prediction of field-scale stress variations should enable further optimisation of hydraulic fracture stimulation treatments.
Addressing sand production challenges — an integrated research approach
Authors: Lim Seng , Wu Bailin , Choi Xavier , Wong Chong Yau , Madon Bahrom , Jadid Maharon , Johar Zurita , Zamberi Amir , Shaffee Amira
Published: August 2017

Sand production may be induced by many factors, such as reservoir pressure depletion, excessive draw-down pressure and water-cut. When transported from the formation, the sand particles can cause serious damage to completion and topside assets, impacting the overall productivity and safety of the operating wells.
The sand management strategy for a particular field requires careful planning, evaluation and implementation to ensure effective and safe well productivity.
The associated CAPEX and OPEX implications and risks can be high if the sanding problem is not managed carefully. This requires a good understanding of field-specific sanding problems.
PETRONAS and CSIRO have collaborated on an integrated research program to provide a better understanding of the critical issue affecting sand production and develop associated predictive tools. This involved a multidisciplinary team from geomechanics, fluid mechanics and mathematics to examine the entire sand production process from sand generation, control and transportation to ensure an optimum sand management strategy.
This extended abstract provides an overview of the research methodology based on experimental and numerical modelling techniques supported by field information. The study focuses on sand production behaviour, as well as failure of down-hole sand control equipment.
The research led to better prediction and quantification of the sand production propensity, as well as erosion severity on critical production equipment. Insights and operational guidelines were also established to assist production and facility engineers in managing sand production challenges.
This integrated research methodology would be applicable to unconventional resource areas, such as coal seam gas or shale gas production.
A simple and practical method for estimating undiscovered hydrocarbons for a specified timeframe
Authors: Eustance Nick , Newman Steve
Published: August 2017

A simple approach has been developed to predict yet-to-find (YTF) hydrocarbons to be discovered in a basin within a specified timeframe. The methodology uses basic exploration and resource data to address the requirement of oil companies, governments, utilities and financial institutions so that these understand the resources available for future markets within a defined timeframe (e.g, in the next 15 years).
In contrast, conventional approaches to estimate the YTF in a moderately mature basin tend to predict the ultimate resource of a basin, unqualified by time. Such techniques reply on data-intensive geological assessments or use the parabolic form of a log-log plot of cumulative hydrocarbon resource against field rank, coupled with an extrapolation of a cumulative resource against field rank (the creaming curve) to an asymptote.
The approach uses annual exploration data, dry hole and discoveries, and the discovery size. Three parameters are defined for the forecast period: the average number of wells per year, the average chance of a discovery, and its average size. Low, mid and high case values of each parameter are estimated, and these are combined probabilistically to produce P90, P50, P10 YTF volumes. These become end points for the forecast period, that are used to extrapolate the creaming curve. Iterating with the input parameters optimises forecasts with respect to the historical dataset. The approach can be extended to predict future field size distributions.
Forecasts are made for the Bonaparte, Browse, Carnarvon and Perth Basins. The total P50 undiscovered gas resource for these basins for the next 15 years is estimated at 25.1 Tcf.
Deep crustal structures interpreted from potential field data along deep seismic sounding transects in Australia
Authors: Kivior Irena , Boyd David , Tucker David , Markham Stephen , Vaughan Francis , Hagos Fasil , Mellon Leslie
Published: August 2017

Energy spectral analysis techniques have been applied to magnetic and gravity data acquired across the Olympic Dam cratonic area in Australia and sedimentary basins along the Equatorial Margin of Brazil. Analysis has been conducted along two Deep Seismic Sounding lines (DSS) acquired by Geoscience Australia. There is a good correlation between interfaces found in this analysis and structures interpreted from the seismic data.
Interpretation of gravity data using energy spectral analysis along the DSS survey lines show a number of deep crustal structures are evident, including the Moho which was detected using gravity data, while similar analysis of the magnetic data show indications of the Curie isotherm. In addition, the analysis was extended away from the seismic lines to detect many deep crustal horizons and structures at considerable distances from the DSS lines.
The results obtained from energy spectral analysis across this area in Australia encouraged the application of this technique on the Equatorial Margin of Brazil, where the potential field data is of much lower resolution. This suggests that a much wider application of this approach could be highly valuable to investigate the deep structure under other sedimentary basins and to assist heat flow studies.
People, productivity and performance: the importance of workplace relations reform to Australia's resource future
Authors: Knott Steve
Published: August 2017

After the past decade of unprecedented global investment into new resource projects and existing mine expansions in Australia, the next few years will see a large number of these new mega-projects finish construction and enter the production phase.
During this industry transition, the performance and productivity of Australia's new resource projects will be critical for delivering the greatest returns to the nation and in determining whether more investment capital will find its way into the country.
As Australia's resource industry rapidly transitions into this new long-term production phase, the author, Australian Mines and Metals Association (AMMA) Chief Executive Steve Knott, discusses how leadership, productivity and workplace relations reform will maximise new production capacity and create ongoing opportunities for future generations. In particular, the author explores why Australia's workplace relations system is an increasing concern for an industry subject to intensifying global competition and the reforms that could assist resources companies to do business, invest and create jobs. This extended abstract about all things people and productivity will examine:

Australia's productivity performance against existing and emerging competitors.
The importance of workplace relations for boosting resource industry productivity and positioning Australia to secure further waves of global investment.
Key reform priorities for resource industry employers, and the workplace policy foundations that the industry needs for future productivity and competitiveness.
Labour productivity in the wider context of skills, leadership and technology usage.
Designing Australia's energy future: applying global learnings to secure Australia's position as a leading global energy supplier
Authors: Leideman Gertjan
Published: August 2017

Low labour productivity, high costs, regulatory instability and remoteness of operations are some issues frequently raised by oil and gas operators and those considering investment in Australia. This extended abstract looks at the next wave of capital investment and presents recommendations on how to sustain Australia’s energy future.
Australia has a significant opportunity to build future resilience and sustained growth through energy reform. This extended abstract draws heavily on the World Economic Forum's global energy architecture performance index (EAPI), developed in collaboration with Accenture, which ranks 125 countries globally on how well their energy system delivers economic growth and development, environmental sustainability and energy security and access.
It is recommended that Australia should apply lessons from the global community and actively implement solutions to sustain the country's energy future. Using case studies from oil and gas regions around the world, recommendations are made to improve competitiveness and secure Australia’s position as a leading global energy supplier.
Unconventional hydrocarbons in shales: source rock or waste zones?
Authors: Mishra Nachiketa , Kaldi John , Schacht Ulrike
Published: August 2017

This extended abstract summarises the objectives of a research project that will provide insight into hydrocarbon generation and accumulation in continuous-source reservoirs and how to best exploit such unconventional resources in Australia, specifically in the Cooper Basin. It compares and contrasts a productive shale from the US—the Bakken Formation—with shales from the Cooper Basin.
Unconventional resources, such as the Devonian-Mississippian Bakken Formation, have been assumed to be continuous source-reservoirs where the oil is generated from organic-rich shales with minimal migration. It is possible, however, that the shale intervals are a waste zone (a leaked seal). These waste zones form when the buoyancy pressure of the hydrocarbon exceeds the capillary forces in the seal, resulting in tertiary migration. Oil saturation values strongly correlate with the hydrocarbon content parameter (S1/TOC) from Rock-Eval. Values of 120 mgHC/gC are typically indicative of non-indigenous or migrated hydrocarbons (reservoirs or leaked seals). Mercury injection capillary pressure (MICP) analysis of core samples can also diagnose whether a shale is a source or a seal. Organic shales with high capillary entry pressures generally have low hydrocarbon content, in line with in-situ generation; shales with low entry pressures have comparatively higher hydrocarbon content and indicate migration from an underlying accumulation.
Once these waste zones are identified on a basin-scale, specific samples from the Bakken Formation will be analysed using micro-scale sealed vessel pyrolysis, combined with monitoring of the biomarkers and other organic compounds using mass spectrometry. As the composition of organic compounds is altered during migration, this will confirm whether they are generated locally or migrated.
Integrating an automated SCADA system with well management: a successful approach
Authors: Kaya Melodi , McCowan Brandon , Kaya Remzi
Published: August 2017

A well-designed SCADA system finds the middle ground between effectively using the latest advances in technology and drawing on the experience of well operators in optimising production from individual wells. Well management methodologies developed and adopted across time by the field operators can be overlooked in the process of designing a SCADA system as the control philosophy of the system is built on a rudimentary understanding of the operation and often does not allow for the subtle nuances that are part of a well operator's daily interaction with a well. One main challenge in designing a system is to capture the art of well optimisation.
It is also important that an effective automated SCADA system meets the needs of other relevant stakeholders in the organisation, such as reservoir engineers, supervisors and business managers. This holistic approach to the design ensures that the data set gathered, which most business decisions will be based on, is uniform across all areas of the company.
This extended abstract describes the experience of integrating an automated SCADA system while incorporating successful well management methodologies for leading Australian CSG operators. It outlines the systematic approach to understanding all aspects of well operation and optimisation, using that information to select hardware and software platforms and then implementing and using the system.
Integrity management—a model for effective implementation
Authors: Boland Michael
Published: August 2017

The management of the integrity of hydrocarbon facilities is of fundamental importance to the duty holder to assure safety, availability of supply, and corporate reputation while minimising operational costs.
The key elements of a robust integrity management system include the application of risk techniques, deploying the right people and the right tools, continuous improvement and governance. The elements in the system need to be implemented effectively.
This extended abstract presents a model that shows how the elements are linked to produce a properly functioning system, including:

Integrity process—data handling and management, including strategies for dealing and aggregating the vast amounts of data, use of predictive technologies, monitoring in conjunction with inspection, application of the right tools and understanding of the real requirements of site activities.
Resources—priorities are properly set so resources that deliver integrity are in place.
Procedures and a documented system—an effective set of documents to underpin the strategy to manage the system.
Measuring performance—effective metrics are crucial to monitor performance and it is also important to close the loop on an annual basis.
Governance—providing effective leadership to make integrity happen.

The effective implementation of an integrity management system benefits the duty holder in assuring continuous improvement in the safety and availability of supply, and protecting corporate reputation while driving down operation costs through continuous improvement and focus.
Recommendations for testing, evaluation and performance requirements for cement wiper plugs in deepwater
Authors: Trogus Michael , Daniel Yves , Farley Doug , Gaspard Gregory
Published: August 2017

Well cementing is a crucial component of deepwater well construction and the key to its success is the performance of the cementing plug. Plug performance is primarily based on its mechanical wiping efficiency and wear resistance. Although, limited understanding of the performance has hindered the establishment of standards, while the American Petroleum Institute Recommended Practice for Performance Testing Cementing Float Equipment (API RP10F) provides recommended testing practices to evaluate the performance of cementing float equipment, however it does not include cementing plugs.
Cementing wiper plugs provides a physical barrier to cement contamination by separating displacement fluid and wiping residual mud film, and other materials, from the pipes’ inside surface. Separation and wiping efficiency are directly related to the plug’s wear resistance and the process of balancing design to achieve optimal stiffness and pressure containment. This design balance is achieved through rigorous material testing and design refinement. The analysis of wiper cuttings samples has provided a clear understanding of the plug’s ability to provide a physical barrier to separate fluids and to function downhole tools. This cuttings evaluation has provided information on material loss and positive fin interference. Results of the evaluation are corroborated by field performance achieved in cementing lengths of casing greater than 16,000 ft (4,876.8 m).
Plug wear is a particular concern in these long, high-volume deepwater casing strings where it can lead to displacement errors and the reliability problems for downhole pressure-actuated tools. These displacement errors are examined in field applications that locate the plug precisely at multiple points during the cementing process.
Digital horizons: technology enabled real-time management of major incident and risk responses
Authors: Lal Alex
Published: August 2017

Exploration, development and production in the oil and gas industry pose major operational risks. The pressure on the industry to manage its assets safely and sustainably, minimising environmental and human impacts, has never been greater. Major incidents or disruptions, if managed poorly, can cause severe reputational damage and directly affect top line growth for years, if not decades.
The emergence of the FLNG model for offshore production is likely to expose a new set of operational resilience challenges for the industry as it introduces new parameters into already complex upstream supply chains, often in remote, environmentally sensitive and/or dangerous locations.
Operational resilience in this sector has traditionally relied heavily on scenario-based planning—identifying a set of possible eventualities, ranking them according to impact and likelihood and putting in place contingency plans for each.
In a challenging financial environment where many projects are becoming marginal and struggling to secure the finance required to develop assets, the prohibitive levels of investment required has tended to mean that only the most critical production and operational systems and processes are designed for resilience.
Despite this, the emergence of more flexible planning approaches and, in particular, more pervasive digital technologies that allow the operating assets at the periphery to communicate and share information in real time with central planning or resourcing functions, are beginning to change the way these challenges are thought about.
From exploration to production—key trends and differences in the exploration and development of hydrocarbons from Australia's established offshore petroleum provinces
Authors: Ewan Howard , Cullen Frances
Published: August 2017

Since peaking at more than 200 MMbbl in 2000, offshore oil production in Australia has declined steadily by falling to below 100 MMbbl in 2011. Various initiatives and policies have been introduced by the Australian Government to encourage exploration of frontier basins to find a new oil province that may stop this production decline.
By analysing the exploration and production profiles of established petroleum provinces in offshore Australia, the reasons behind similarities, differences and trends can be understood. This knowledge can be applied to future exploration efforts and provides a variety of possible outcomes should success come in immature and frontier provinces.
Analysis of data mainly from the Bonaparte, Browse, Gippsland, North Carnarvon and, to a lesser extent, the Otway and Perth basins, shows that early success typifies these petroleum provinces.
The degree of early success is, however, not always a good indication of later exploration results. While the creaming curves of some basins conform to the hypothetical basin creaming curve, characterised by large initial reserves increases and falling discovery size across time, it is evident that this cannot be universally applied. Considerable success much later in the exploration history of a basin is demonstrated, by success driven policy implementation, exploration incentivisation and increases in data acquisition.
In this extended abstract, the importance of using advances in technology is demonstrated by reserves additions following the opening up of deepwater areas and the increased use of high-density 2D seismic and 3D seismic data. This information supports the notion that frontier areas may hold the key to alleviating dependence on foreign supply, success in immature basins is still possible and should not be overlooked.
Unitisation of petroleum project interests
Authors: Kenneth Wee
Published: August 2017

Traditionally, the unitisation of oil and gas project interests involved the exchange of legal ownership interests between project proponents to achieve uniformity of their licence interests across the project. Recently, more contemporary and creative forms of unitisation have emerged including economic, beneficial and contractual unitisation approaches that do not necessarily involve the transfer of legal title interests. Unitisation is a way of pooling resources to improve the likelihood of an economically viable project for participants and to overcome practical challenges resulting from uneven interests in the component parts of a broader project. In some cases, unitisation is the catalyst for project sanction. Achieving agreement and alignment on the most equitable unitisation outcome, including the valuation of the relative resource base and ownership stakes, is not easy. It involves navigating a myriad of legal, commercial, operational and financial considerations. A project residing in both federal and state waters can add increasing layers of complexity due to the interaction between overlapping federal and state jurisdictional and taxing rights. This extended abstract discusses key issues arising in various unitisation models and considers the associated fiscal implications from income tax, capital gains tax, petroleum resource rent tax and royalty perspectives. It also examines the government’s announced tax measures for dealing with the swapping of interests or interest realignments resulting in a common development project and the impact and effectiveness of these rules on unitisation arrangements.
Sales and marketing of LNG is evolving. Are you prepared?
Authors: Georgievski Alex , Hamilton Jamie , Gervasoni Giulia , Tan Priscilla
Published: August 2017

Australia is in the process of transitioning from the project build phase to the project operating phase in the LNG lifecycle. By 2020, the number of operating LNG trains will grow from nine to 21, and it is expected Australia will challenge to be the world’s largest exporter of LNG. LNG sales and marketing activity is expected to increase dramatically across the Asia-Pacific region.
But what does this change mean for LNG players in the Asia-Pacific region? And what needs to be done to prepare for it? There is presently very little information available on how prepared LNG companies in the Asia-Pacific region are to undergo this transition. Equally, the maturity of the risk management and trading functions of the more established companies in the sector, and how much work less-experienced companies need to do to meet global standards, has been relatively opaque.
To bridge this information gap, Deloitte conducted a targeted global survey of LNG participants, particularly focusing on their energy trading risk management (ETRM) maturity. Deloitte also sought the industry’s views on the changing market, and challenges and opportunities for the future.
The results show the following:

There is a significant divide between established global integrated multi-energy commodity companies and regional Asia-Pacific LNG companies in terms of their ETRM maturity.
Organisations with existing marketing and trading functions covering commodities with more mature markets have been able to leverage past lessons and existing ETRM capability across their portfolios. For other companies without this experience in mature markets, the evolving developments and liquidity of global LNG markets presents both significant threat and opportunity.
The transition in LNG markets, and the increase in sales and marketing activity, will place high demands on existing and new operations—and their owners—to establish and mature their marketing and trading functions. An ETRM framework is a crucial part of meeting these demands.

In this paper the authors examine the background to this transition, what the essential components of an ETRM are, and how far away Asia-Pacific LNG players are from being prepared for transition and achieving maturity in this area.
The application of risk-based methods to multilateral well design
Authors: Nguyen Lucien Jason , Pickering Paul F. , Aman Zachary M.
Published: August 2017

Horizontal and multilateral oil and gas wells are used to maximise hydrocarbon recovery while reducing the required well count and associated costs. Presently, lateral lengths are designed using semi-quantitative methods. Guided by a desire to minimise the risk of poor well deliverability, the tendency is to design producing lengths longer than required, with the rationale that the well connects with sufficient hydrocarbon bearing reservoir to provide good deliverability. Drilling long producing lengths, however, is expensive and generates a higher risk of drilling and lifecycle (intervention and workover) problems. Furthermore, attempting to increase deliverability by extending the producing length encounters the law of diminishing returns as the flow becomes constrained by tubing friction loss.
This paper seeks to quantify the optimal length for a horizontal well for a given range of reservoir conditions through multiphase fluid modelling and stochastic analysis. A discretised horizontal well model was created, which shows how changing the well length transforms the probability density function of the production rate for the well. A parametric case study was conducted, which demonstrates the evolution of the optimal well length and production rate with parameters including well diameter, fluid viscosity and well flowing bottomhole pressure. A simplified economic analysis illustrates the incremental change in discounted cash flow and quantified risk from drilling a longer well. The model also considered the influence of inflow control devices (ICDs) to adjust the inflow to match permeability and even-out inflows along the producing length, thus reducing the risk of gas and water coning, and improving hydrocarbon recovery.
What have we learned? Insights from a decade of bias research
Authors: Welsh Matthew , Begg Steve
Published: August 2017

Cognitive biases—unconscious errors resulting from how people’s minds work—have been observed in both laboratory and in situ examinations of petroleum personnel’s decisions, and have been demonstrated to result in significant lost value. Since 2003, the CIBP group at the Australian School of Petroleum has been conducting research into such effects, including the use of a battery of questions designed to test oil and gas personnel’s susceptibility to said biases.
This paper tracks industry performance on biases across the last decade, noting changes relative to baseline results from Welsh et al (2005) and on insights since gained into the nature and operation of cognitive biases more generally. Results are discussed in light of standard findings regarding the strength of biases observed in the wider psychological literature and in direct comparison with results observed in a sample of petroleum students collected from 2005–15, providing valuable benchmarks.
The central observation is that bias strength has remained stable across the period in question, according with earlier studies suggesting biases are robust and increased awareness of their existence is insufficient to reduce bias susceptibility. Given this observation, the authors look in finer detail at what can be done, discussing the benefits ongoing training regarding the nature of biases can provide, before describing debiasing techniques and changes to the elicitation methods and tools known to reduce bias, based on state-of-the-art understanding of when and how biases occur. This, the authors argue, offers significant opportunities to reduce bias and improve industry decisions and economic outcomes.
The hydrocarbon potential of the 2016 proposed Offshore Acreage Release Areas for petroleum exploration
Authors: Bernecker Thomas , Heugh Aaron , Higgins Karen , Owens Ryan
Published: August 2017

The Australian Government usually releases new offshore exploration acreage once a year. The proposed 2016 Release Areas are located across various offshore hydrocarbon provinces and include mature basins with ongoing oil and gas production as well as exploration frontiers. In support of the annual acreage release, Geoscience Australia provides a variety of geological information with an emphasis on basin evolution, stratigraphic frameworks, and overviews of hydrocarbon prospectivity. Geoscience Australia’s petroleum geological studies are aimed at the evolution of hydrocarbon-bearing basins at a regional scale, and include a review of source rock occurrences, their distribution and geochemical characters.
Following the recent oil discovery in the Roebuck Basin, a strong focus of Geoscience Australia’s work is being placed on the Triassic period, and any new findings will directly underpin the release of new exploration acreage.
Recent updates to stratigraphic frameworks and new results from geochemical studies are regularly published, and are used by Geoscience Australia for prospectivity assessments. Furthermore, the Australian Government continues to assist offshore exploration activities by providing ready access to a wealth of geological and geophysical data.
2015 PESA production and development review
Authors: Evans Ross , Close David , Richards Brenton , Ilett Rachael
Published: August 2017

Low oil prices through 2015 challenged oil and gas operators to cut costs and minimise expenditure to survive the long cold winter of low pricing. Oil production decreased more than 10%—relative to 2014—to 128 mmboe for 2015. In 2015, natural gas production of 2,611 PJ was relatively consistent with 2014 production, with the exception of the Bowen and Surat basins, where production more than doubled to over 630 PJ. The primary driver for the increased Bowen and Surat basin output was the first full year of operation of QCLNG and, to a lesser extent, the startup of GLNG in the fourth quarter of 2015.
The start-up of two major LNG operations in Queensland, followed by a third (APLNG) within the first weeks of 2016, is a transformational event for the eastern Australian gas market. As each of the projects has commenced exports during an extremely long—and therefore low-price—LNG market, there is intense market pressure on these projects to improve profitability through efficiency improvements and cost reductions. In contrast to Australia’s other LNG exporters, which are all fed by offshore conventional fields with relatively few wells, the Queensland projects have the opportunity to benefit from constant improvements to upstream operations as they continue to drill hundreds of wells to sustain the LNG operations. North American operators have continuously improved during the past decade of unconventional gas development and this provides a proof of concept that is encouraging for Australia’s aspirants. Effective cost reductions have already been announced by operators in Queensland; maintaining these reductions as the market improves will be critical to the success of the Queensland CSG to LNG projects, and expanding efficient and cost-effective operations to other onshore basins provides an opportunity for the Australian industry-at-large.
Preparing for a carbon constrained economy: managing compliance and cost
Authors: Papon Frederic , Smith Susie
Published: August 2017

Australia’s greenhouse gas emissions reduction target of 26–28% by 2030 will require an effective emission reduction of 46% from business as usual emissions. Along with the Emissions Reduction Fund, the Safeguard Mechanism is a central component of the Australian Government’s plan to meet its targets.
It is vitally important that businesses understand the compliance obligations, costs and opportunities as industry transitions to a lower carbon economy.
From 1 July 2016, the Safeguard Mechanism will begin placing a compliance obligation on any emissions above legislated facility baselines. Entities exceeding their baselines will be required to surrender Australia Carbon Credit Units (ACCUs) to the regulator.
There are, however, a range of commercial strategies that companies can adopt to manage their compliance obligation.