bluuebunny/crossref_metadata_2025 huggingface dataset:
A CASE STUDY OF A CARBON DIOXIDE WELL TEST
Authors: Xu J.Q. , Weir G. , Paterson L. , Black I. , Sharma S.
Published: August 2017

This paper reports on the planning, procedure, results and analysis of a carbon dioxide (CO2) well test performed on Buttress–1, a well located in the Otway Basin, Victoria, Australia. A large-scale pilot study of CO2 sequestration is planned by the Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) in this area, which will involve, inter alia, taking CO2 from the Buttress reservoir and injecting it into a nearby depleted gas field. Understanding the production characteristics of this well is important to the success of this pilot, which forms part of a more extensive study to establish viable means to mitigate CO2 emissions to the atmosphere. This general backdrop forms the motivation for this study.Testing comprised of a standard suite of draw-downs and build-ups to determine reservoir/well characteristics, such as the well deliverability, the non-Darcy skin coefficient and the average reservoir permeability and volume.Compared to the wealth of experience developed over many years in testing oil and gas wells, the collective experience in CO2 well testing is extremely limited. The distinguishing features between this test and those of a typical natural gas well test need to be emphasised. Although, in general, flow testing a CO2 well should be similar to testing a natural gas well, differences in the thermodynamic properties of CO2 affect the analysis of the well test considerably. In particular, the non-Darcy skin effect is more pronounced and the wellbore and surface flow can involve dramatic phase changes, such as the formation of ice. Also, since CO2 is more compressible than a typical natural gas, the accurate measurement of the flow rate becomes more challenging. It is also apparent that the use of pseudo pressure, as opposed to simpler methods of dealing with the pressure dependency of key properties, is essential to the successful analysis of the pressure response to the CO2 production.
NOVEL OFFSHORE LNG SOLUTIONS
Authors: Driver J. , Graff O.F. , Eie R. , Lund T. , Woodhouse S.
Published: August 2017

The demand to process associated and stranded gas is growing and there is increasing commercial interest in offshore LNG production. Limitations in available land and carrier access, safety and environmental considerations and difficult onshore permitting have created an interest in locating LNG terminals offshore. These factors are providing incentives to develop solutions and the technologies required to transfer the liquefaction and re-gasification segments of the LNG chain to offshore locations. Some of the hurdles that need to be overcome are associated with equipment size, weight and layout, energy consumption, the marine environment and, for floating facilities, the moving environment. All of these aspects need to be addressed to produce an overall design that meets technical, commercial, safety and environmental requirements. This paper presents some recent developments in offshore LNG solutions for floating and fixed offshore LNG production and offshore LNG re-gasification terminals. Specific case studies for each facility are: a floating LNG production facility for the Nnwa-Doro gas field offshore Nigeria; a fixed offshore liquefaction facility in the Arctic region; and, the Adriatic LNG receiving terminal located offshore Italy. Information about an alternative method of transporting natural gas—called heavy liquefied gas (HLG)—which has some specific advantages over traditional LNG, is also presented. For each case study, design, construction, cost and schedule are discussed where applicable.
THE VIRTUOUS LIFE CYCLE FOR EXPLORATION AND PRODUCTION—LEAD AND LAG FACTORS
Authors: Goldstein B. A. , Alexander E. , Cockshell D. , Malavazos M. , Zabrowarny J.
Published: August 2017

‘High-trust societies fare better than low-trust societies,’— Francis Fukuyama.1Trusted land access is both the first factor and the final outcome of a virtuous exploration and production life cycle. Key leading factors in the stewardship of trusted land access and a virtuous life cycle for exploration and production in South Australia include:evolutionary, best practice, objective-based legislation;transparent statements of environmental objectives (SEOs) that enable regulators to provide a one-stopshop for approvals and avoid capture;administrative arrangements between government agencies to foster expeditious co-regulatory work-flows;conjunctive native title land access agreements that are fair and sustainable in relation to development;prioritised, pre-competitive studies that reduce critical uncertainties; and,highly motivated government officers focussed on building trust and reducing uncertainties, so both the community and investors sustain positive expectations for outcomes from exploration and production investment.This paper characterises the South Australian Government’s roles and measures for success in the virtuous life cycle for petroleum and geothermal resource investment. The critical importance of local, leading actions will be demonstrated with examples, including: proposed enhancements to South Australia’s Petroleum Act 2000; streamlined but stringent project approvals; progressive achievements in native title land access agreements; the evolution of Australia’s geothermal energy sector; and, perception moulding research in the Cooper, Otway and Officer basins.
TAXATION OF FINANCIAL ARRANGEMENTS —FURTHER DEVELOPMENTS
Authors: Murray J.H.
Published: August 2017

On 3 January 2007 the Minister for Revenue and Assistant Treasurer Peter Dutton released revised exposure draft legislation and explanatory material in relation to the taxation of financial arrangements that would ‘reduce uncertainties and distortions’. Further Mr Dutton said that:‘The reforms will lead to lower costs for financial activities conducted by business and result in improved competitiveness and great efficiency in the general operation of Australia’s financial markets.’This release followed a previous exposure draft released for consultation purposes during December 2005. Many changes have arisen as a result of the consultation process and the current draft is a positive step in providing a comprehensive code to regulate this area. As with any proposal there remain issues that are uncertain; however, the Government is committed to the consultation in relation to the current draft.At a high level this legislation allows taxpayers to more closely align the tax treatment of financial arrangements to accounting treatment.The exposure draft is incomplete in that it does not contain rules to address the tax treatment of synthetic financial arrangements and Treasury has left open whether further integrity measures will be introduced.This paper seeks to outline the primary provisions proposed in the draft legislation and discuss in general terms what the changes may mean to companies operating in the oil and gas industry. Further, the paper recommends several steps that companies can take now to prepare themselves for the introduction of the law.
Water washing: a major hydrocarbon alteration process. Part 1—geochemistry
Authors: Elliott Lindsay
Published: August 2017

This paper presents the geochemistry portion of a larger study attempting to better predict hydrocarbon type prior to drilling. The geochemistry indicates that condensate-gas or gas-oil ratios have a predictable relationship with gasoline-range hydrocarbon solubility. The study shows that soluble gasoline-range aromatic compounds such as toluene are significantly depleted in oils compared with gases, whereas more insoluble compounds such as methylcyclohexane are enriched.
The review indicates that water-washing in the reservoir is a major alteration process affecting hydrocarbon type and, in extreme cases, can convert a major gas accumulation into a smaller oil accumulation. Source type and maturity have a relationship with the volume of liquids produced, but are not the primary control on the hydrocarbon phase in the reservoir.
The water-washing process will also affect carbon dioxide geosequestration projects, particularly where injection into abandoned low GOR oilfields is proposed.
Climate change—a new consumer mindset: creating new business opportunities and challenges
Authors: Abood David , Cullinane Bernadette
Published: August 2017

Are individuals ready to act and take concrete action to address climate change? Will consumers try to use their buying power to reduce the level of emissions? And will they be prepared to pay more for products and services that help achieve this objective? The answer to all of these questions appears to be yes.
Up to now, it has been difficult for companies in the resources industries such as utilities and oil and gas businesses, to gauge the potential impact of consumer action on their businesses.
Now, a new survey of more than 7,500 consumers worldwide shows that consumers across the globe are not just aware of climate change as an issue, but are adopting a new mindset that will change the basis on which they make buying decisions. Designed by Accenture, the survey shows in particular that consumers will favour providers whose products and services make a positive contribution to tackling climate change—and will look unfavourably on those that ignore the issue.
Environmental update for 2007
Authors: Baird Gordon , Lorkin Mark
Published: August 2017

This environmental update for 2007 covers key environmental issues and development updates for the upstream oil and gas industry in Australia. Driven by market opportunities, the continued significant growth in the exploration and development of oil and gas reserves in Australia is considered against the environmental issues and challenges this growth presents. The number of large projects is testing regulatory approvals processes at a time when there is an ever rigorous and adapting regulatory climate, an increasing need for stakeholder engagement, and sustainability considerations.
The review includes a summary of the environmental approval status of the large number of LNG projects in their various stages of development, as well as summary statistics on oil and gas activities in relation to assessment under the key Commonwealth environmental assessment legislation, the EPBC Act. An overview of changes in the main oil and gas legislation is also provided.
Major environmental issues affecting the oil and gas industry are summarised, along with details of some of the main areas of ongoing environmental research initiatives.
Finally, a summary of the review draws together the matters described in the environmental update for 2007.
The Halladale and Black Watch gas fields—drilling AVO anomalies along Victoria's Shipwreck Coast
Authors: Constantine Andrew , Morgan Glenn , Taylor Randall
Published: August 2017

The Halladale and Black Watch fields are adjacent fault-dependent gas accumulations at the Turonian Waarre Formation level situated in the eastern Otway Basin, about 4–5 km from shore in VIC/RL2(v). The two fields were first identified in 2002 when anomalous seismic amplitudes were observed on the tail-ends of several 90s-vintage 2D lines that extended into what was then vacant acreage. After being awarded the block as VIC/P37(v) Origin Energy Limited and its joint venture (JV) partner, Woodside Energy Limited, acquired a 211 km2 full-fold 3D seismic survey over the anomalous amplitudes in late 2003. Subsequent analysis of the seismic volume revealed two tilted fault blocks with strong amplitude variation with offset (AVO) anomalies in the Waarre A and Waarre C units that conformed to structure and appeared to shut off at the same depth. A similar AVO anomaly was also observed in the overlying Santonian Nullawarre Formation, raising the possibility that Halladale and/or Black Watch had leaked or were leaking. In early 2005, the VIC/P37(v) JV drilled two exploration wells targetting the key Waarre C reservoir on the eastern flank of Halladale and eastern crest of Black Watch. Both wells encountered live gas columns in the Waarre C but no GWCs were observed on logs and wireline pressure data indicated the two fields were not in pressure communication. A third well was then drilled down-dip of the Waarre C AVO shut off on the Halladale fault block to obtain a water gradient from the Waarre C. This well proved invaluable in determining the height of the gas columns in the Waarre C at both fields as it showed the gas-water contacts (GWCs) at Halladale (1,760 mSS) and Black Watch (1,770 mSS) were shallow to their respective AVO shut offs by about 20 m and 10 m respectively. Subsequent analysis of shear wave sonic data from the third well indicated there is a 17 m residual gas column at the base of the Halladale Field. This suggests Halladale either leaked slightly at some time in the past or is still leaking. A similar scenario may also occur at Black Watch. Given the close proximity of the two fields to the coast, development scenarios from onshore are now being considered.
Laboratory and well-history based predictions of productivity decline due to oilfield scaling—analytical modelling and field study
Authors: Carageorgos Themis , Marotti Marcelle Pinto , Monteiro Raphael , Bedrikovetsky Pavel
Published: August 2017

Sulphate scaling may develop during offshore waterflood projects where mixing of injected and formation waters causes salt precipitation. Salt deposition results in permeability decline and, consequently, in impairment of well productivity. The problem has been widely presented in the literature for the North Sea, Campos Basin and the Gulf of Mexico. Recently several oil companies have reported several field cases of oilfield scaling in Australia.
In this paper, methods are summarised for forecasting productivity decline from the history of well productivity index decline, produced water composition, and also from laboratory corefloods. The methods account for chemical reactions based on exact analytical solutions of inverse and forward modelling of quasi steady state oil-water flow towards producing wells. The main result obtained from the analytical model is a measure of the decline in productivity index with time for either linear flow in the case of a coreflood or the radial flow towards well.
The analytical model has been used to predict further productivity decline in scaled-up producers of the deepwater offshore field X (Campos Basin, Brazil). Laboratory corefloods were carried out for field X cores and waters, and the model coefficients were determined. The productivity losses due to barium sulphate scaling have been noticed during several years of seawater flooding. The values obtained for reaction kinetics and formation damage coefficients are similar to those obtained from corefloods.
Pluto—a major gas field hidden beneath the continental slope
Authors: Tilbury Larry A , Clayton Chris J , Conroy Tim J , Philip Giles , Boyd Georgia A , Johnson Glen A , Rayfield Mark A , Hartanto Lina , Lance Dane P
Published: August 2017

The Pluto gas field, North West Shelf of Australia, was discovered in April 2005. It is located in production licence area WA-34-L some 190 km northwest of Karratha, and is situated beneath the continental slope in water depths of 400–1,000 m.
The seabed topography initially hindered the recognition of this field. The presence of large seabed channels and steep dips in the overburden, together with the variable water depth, result in seismic ray-bending effects which reduce the quality of imaging and attenuate amplitudes over the southern and eastern parts of the field. Consequently the depth conversion of seismic data over the Pluto structure has been a key uncertainty for the field definition.
Structurally, the trap is a tilted fault block, bounded on the west and north by major bounding faults, and sealed by overlying regionally extensive shales. The Triassic reservoir sequence dips gently to the east, and subcrops against the regional Jurassic Unconformity.
Pluto–1 encountered a gross gas column of around 209 m in Triassic sands of the Mungaroo Formation and Tithonian sands, sealed by Cretaceous shales of the Forestier and Muderong formations. Petrophysical analyses of the conventional wireline dataset confirmed an average net porosity of 28% and average gas saturation of 93% for the Mungaroo Formation (Lower E Unit). Production tests proved the high deliverability of the Mungaroo E Unit (46.5 MMscf/d) but showed the Tithonian section to be of poor deliverability (9.5 MMscf/d with possible in-wellbore leakage from the deeper Mungaroo DST).
Since the discovery, five appraisal wells (excluding sidetracks) have been drilled to delineate the accumulation, and to target areas of higher quality sand development for optimisation of development well locations. In addition, the Pluto 3D data has been twice processed to a pre-stack depth migration—once, immediately following the Pluto–1 discovery to aid in the appraisal campaign and then again following final investment decision (FID) to take advantage of new and improved techniques for seismic processing which has led to increased confidence in the proposed development well locations.
The Xena gas field, a satellite field adjacent to Pluto, was discovered by Xena-1ST1 in September 2006. Since then a further two appraisal wells have been drilled to delineate the structure and define the accumulation.
The Triassic reservoir section has been extensively cored, logged and analysed in detail for reservoir characterisation and correlation. The reservoir is composed of thickly developed, amalgamated fluvial multi-valley sandstones of the Mungaroo Formation, and coastal plain sediments (tidal bars and channels, estuarine beach deposits) of the more tidally influenced Brigadier Formation.
Developing Aussie home-grown talent in an international market
Authors: Pritchard Tim
Published: August 2017

With the current skills shortage in the engineering profession and the need for more experienced engineers, it is important for Australian engineering companies to not only rely on importing skilled engineers from overseas to fulfil current day demands, but also to focus on developing young Australian engineers for the future.
Aker Solutions Australia has implemented a training and development program for its employees by seconding them into the head office in Oslo, Norway for both technical and personal development. The program provides many positive outcomes for both the company and the employees including: knowledge transfer and alignment between the international offices, developing and improving the talent of Australian engineers, improving communications between the offices and providing the Oslo office with much needed resources. The program was initiated in 2006 and so far nine employees have been sent across the globe for training.
In this time the employees have had the opportunity to work on new technological developments in gas processing, advanced concept development studies and large scale engineering, procurement and construction (EPC) projects. Working internationally has also provided Australian engineers with a chance to interact with a number of skilled people from diverse backgrounds, learn new languages and embrace different cultures. The program to date has had much success, with both clients and the Aker Solutions office in Norway requesting continuation of the Australian engineers’ services while one of the engineers—Jacqui Driver—won best paper at the 2007 APPEA conference for her work in Oslo on novel offshore LNG solutions.
The Permian–Triassic boundary in Western Australia: evidence from the Bonaparte and Northern Perth basins—exploration implications
Authors: Gorter John , Nicoll Robert S , Metcalfe Ian , Willink Robbert , Ferdinando Darren
Published: August 2017

Several sedimentary basins in Western Australia contain petroleum reservoirs of Late Permian or older age that are overlain by thick shaly sequences (400–2,000 m) that have been assigned an Early Triassic age. The age of the base of the Triassic shales has been, and continues to be, contentious with strata being variously ascribed to the latest Permian (Changhsingian Stage) or wholly in the earliest Triassic (Induan Stage). In the Perth Basin the Permian-Triassic boundary appears to be located somewhere in the Hovea Member of the Kockatea Shale. In the Bonaparte Basin, the boundary would appear to be either in the uppermost Penguin Formation or at the boundary between the Penguin and Mairmull formations.
The uncertainty of the boundary placement relates to the interpretation of the sedimentological, biostratigraphic and geochemical record in individual sections and basins. Major problems relate to the recognition, or even the presence of unconformities, complications related to the presence of reworked sediments and paleontological material (both conodonts and spore-pollen) and to the significance of geochemical shifts.
The age of the basal Kockatea Shale (northern Perth Basin) and the basal Mt Goodwin Sub-group (Bonaparte Basin) is reassessed using palaeontological data, augmented by carbon isotopic measurements and geochemical analyses, supported by wireline log correlations and seismic profiles. The stratigraphy of the latest Permian to Early Triassic succession in the Bonaparte Basin is also revised, as is the nomenclature for the Early Triassic Arranoo Member of the Kockatea Shale in the northern Perth Basin. The Mt Goodwin Sub-group (new rank) is composed of the latest Permian Penguin Formation overlain by the Early Triassic Mairmull, Ascalon and Fishburn formations (all new).
Performance of swirl tube oil-water separator for downhole applications
Authors: Wong Chong Yau , Noui-Mehidi Mohamed Nabil , Wu Jie
Published: August 2017

An experimental comparison is made between a 2 inch (50.8 mm internal diameter) liquid-liquid cylindrical cyclone (LLCC©) and a 2 inch CSIRO-patented liquid-liquid separator (CS-T). Flow visualisation by long-time exposure photography of the LLCC revealed a steady vortex core with a fixed orientation that is independent of the inlet watercut percentage. Visualisation of the CS-T revealed an inverted cone that varied with length at decreasing watercut at the inlet stream. Volume fraction studies showed that the CS-T separation characteristic is similar to the LLCC at the 50% split ratio, but this characteristic departs markedly at higher split ratios. For a watercut of 94%, the optimum split ratio for the present LLCC and CS-T are 55% and 58% respectively.
Review of the 2009 offshore petroleum exploration release areas
Authors: Bernecker Thomas
Published: August 2017

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. This year, 31 areas plus two special areas in five offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or twelve months after the release date (i.e. 3 December 2009 and 29 April 2010), depending on the exploration status in these areas is and on data availability.
The 2009 release areas are located in Commonwealth waters offshore Northern Territory, Western Australia, South Australia and Victoria, comprising intensively explored areas close to existing production as well as new frontiers.
As usual, the North West Shelf features very prominently and is complimented by new areas along the southern margin, including frontier exploration areas in the Ceduna Sub-basin (Bight Basin) and the Otway Basin.
The Bonaparte Basin is represented by one release area in the Malita Graben, while five areas are available in the Southern Browse Basin in an under-explored area of the basin. A total of 14 areas are being released in the Carnarvon Basin, with eight areas located in the Dampier Sub-basin, three small blocks in the Rankin Platform and three large blocks on the Northern Exmouth Plateau (these are considered a deep water frontier).
In the south, six large areas are on offer in the Ceduna Sub-basin and five areas of varying sizes are being released in the Otway Basin, including a deep water frontier offshore Victoria. The special release areas are located in the Petrel Sub-basin, Bonaparte Basin offshore Northern Territory, and encompass the Turtle/Barnett oil discoveries.
The 2009 offshore acreage release offers a wide variety of block sizes in shallow as well as deep water environments. Area selection has been undertaken in consultation with industry, the states and Territory. This year’s acreage release caters for the whole gamut of exploration companies given that many areas are close to existing infrastructure while others are located in frontier offshore regions. As part of Geoscience Australia’s Offshore Energy Security Program, new data has been acquired in offshore frontier regions and have yielded encouraging insights into the hydrocarbon prospectivity of the Ceduna-Sub-basin.
Rigless well intervention and trees on wire from a DPII vessel: a case study
Authors: Glennie Simon , Leeson Tom , Rowson Ian , Morrison Bevan
Published: August 2017

The Vincent field development is typical subsea development with 11 subsea wells required to be tied back to a central production facility.
In 350–400 m of water all subsea operations would be diver-less and the well costs associated with using a semi-submersible rig would be a major element of the total field cost.
Sequencing construction vessel and drill rig activities, and aligning this sequence with availability of suitable vessels is often a major challenge on such projects. This was accentuated on this development by the shortage of suitable vessels. In addition to this, multiple mobilisations—potentially incorporating lengthy, expensive transits from Singapore—drove a desire to minimise the use of specialist vessels.
The challenges in reducing well costs by using rigless operations are both technical and commercial. Technically, the operations and proposed equipment must be matched to the capabilities and functionality of the vessel. Commercially, sufficient work needs to be identified to justify the one-off costs of preparing and mobilising the vessel and equipment, preparing the operations program, and training and familiarising the personnel.
In this instance, the operator identified sufficient work to make the vessel mobilisation and equipment preparation worthwhile while not committing to a long-term deployment. Recognising the multi-role capability of the vessel permitted additional work on nearby assets. These removed the need to mobilise additional vessels to the field and improved vessel’s economy in well intervention mode.
Other factors that ensured value was gained from the rigless approach included:

the rig schedule being de-coupled from product delivery;
the drilling program with limited drilling assets was accelerated, protecting first oil; and,
the need to re-configure or modify a rig for Xmas tree (XT) handling was removed.
Initial preparations for the planned operations began in the latter part of 2006. The main activities were to:

confirm the specification of the subsea lubricator system and its deployment system;
undertake a detailed hazard and risk assessment process on all operations;
undertake an operability study for crane and deployment system;
complete the modifications to the vessel for its intervention role; and,
prepare detailed well programs and procedures for equipment operation.
The design and fabrication of project-specific interface equipment between the subsea lubricator and the subsea Xmas trees, and specification of the required well services equipment such as wireline, pumping and fluid handling services were also required.
As this represented the first time such operations had been undertaken in the region by the contractor or by the operator, a large number of supporting systems were required to be developed, adopted and managed, most notably:

well control and barrier philosophies;
emergency shutdown and disconnection (ESD) philosophy;
project management processes; and,
personnel training and familiarisation programs.
Use of innovative technology to manage impacts in a sensitive environment
Authors: Jarvis Samantha , Grebe Cameron , Lively Richard
Published: August 2017

In 2008 Woodside Energy Ltd, as operator of the Browse LNG Development, completed the Torosa–6 appraisal well in the south lagoon of Scott Reef, which is about 425 kilometres north of Broome, Western Australia. The well was drilled with the Wilcraft jack-up rig (Fig. 1) and was part of the appraisal program for the Torosa gas field. About half of this field lies beneath the shallow-water coral atolls of Scott Reef.
The well involved a number of innovative technologies to minimise the environmental footprint while achieving the appraisal objectives. The approach adopted a custom-built riserless recovery system to collect the cuttings and mud from the riserless section of the well, combined with a purpose built cuttings containment and slurrification system to recover the cuttings and mud from the well for disposal away from Scott Reef. This well represents a significant demonstration of the industry’s responsible approach to operating in sensitive areas. The drilling of the Torosa–6 well provided a number of challenges due to the environmental sensitivity of the area, requirement to obtain regulatory approval at both the state and Commonwealth levels and the need take stakeholder expectations into account.
Electricity generation in a carbon constrained world: the role for gas
Authors: Stanford Jon
Published: August 2017

In March 2009, the Australian government published draft legislation for its proposed emissions trading scheme—the Carbon Pollution Reduction Scheme (CPRS). The CPRS is the main instrument that will be employed to achieve Australia’s stated objective of greenhouse gas mitigation, together with the new renewable energy target (RET) mandating that 20% of Australia’s electricity will be provided by renewable energy by 2020. The stated objective is to achieve a 5% reduction in emissions from the year 2000–2020.
The objective of a 5% reduction in emissions (identified as CPRS-5 in the Treasury modelling undertaken for Garnaut and the Australian Government) is a more modest target than scientific opinion tells us is required to achieve temperature stabilisation at a level around two degrees higher than the average level now.
Yet this target has been selected on the assumption that the rest of the world does not take more substantial action. If Australia seeks to achieve more than the rest of the world there will be a negligible impact on global emissions while we will export investments and jobs to less ambitious countries.
In any case, a 5% reduction in emissions from 2000 levels will be difficult to achieve in the absence of major technological change being realised before 2020. It represents a reduction from the year 2000’s levels of 25% in per capita terms, and around 25% from projections of emissions under business-as-usual assumptions.
Stationary energy, mainly power generation, is responsible for about half of Australia’s greenhouse gas emissions. Because this is also a sector where low emissions technologies are already available, it is expected that much of the heavy-lifting in regard to greenhouse gas mitigation will have to come from this sector.
Much of the new investment in the power generation sector to 2020 will come from renewables so as to meet the RET, which equates to around 45,000 GWh of renewable generation by 2020.
But what of base load generation? Apart from geothermal, that has yet to be technically and commercially proven in Australia, renewables are generally ill-suited to base load generation.
Base load power in Australia has traditionally been provided by black and brown coal and with its high emissions it is unlikely to be seen as a future option in a carbon-constrained world. Lower emissions options for base load generation include:

coal with carbon capture and storage (CCS);
geothermal energy;
nuclear energy; and,
combined cycle gas turbine (CCGT).
The first three options are all problematic in Australia, and would not be able to provide significant generation capacity before 2020.
Reporting of reserves and resources: the not so short path towards transparency
Authors: Curtin Russell
Published: August 2017

In the free-market environment, one of the key performance indicators investors look for in listed oil and gas companies is the quantity, replacement and growth of the proved reserve base. For national governments and authorities, this resource base provides equally crucial information when planning, defining budgets, securing supply and establishing policies that stimulate investment and protect consumers. However, current codes to report reserves and resources lack a universal standard and in many cases have not been updated to reflect advances in technology.
In the absence of a clear set of universal standards, there is potential for inconsistent reporting of reserve figures that are not directly comparable to each other, or require substantial revisions. This in turn can leave investment decisions open to discretionary interpretation, with damaging consequences such as loss of credibility in reserves figures and the subsequent market volatility associated with uncertainties in the reserves and resources base.
Disclosing the basis for reserves and accounting estimation is fundamental in preparing an accurate company valuation. As the nature of reserves reporting relies on assumptions and estimates, a transparent framework for disclosure that meets the needs of users would be a huge step forward.
Both the US Securities and Exchange Commission (SEC) and International Accounting Standards Board have been actively working on reporting requirements. This presentation will explore the recent developments in oil and gas company reporting requirements, including those recently announced by the SEC.
A case study of the Flex LNG/Rift Oil floating LNG project in Papua New Guinea
Authors: Dighton Peter
Published: August 2017

Flex LNG Limited is a producer of units for the production, storage and off-take of liquefied natural gas (LNG). It currently has four of these units committed for construction by Samsung Heavy Industries in Korea, utilising the SPB LNG containment system. The world’s first floating liquefaction unit will be delivered to Flex in 2012. Floating LNG facilities have unique potential for monetising uncommitted gas reserves.
In June 2008 Flex and Rift PLC entered into a co-operation agreement under which they agreed to work together to develop a floating liquefaction project offshore Papua New Guinea (PNG). The project will utilise Rift’s gas reserves and one of Flex LNG’s floating liquefaction units. Annual production capacity will be 1.5 million tonnes of LNG and start-up is targetted for 2012.
The paper will be a case study of this project including: critical path, project structure and contractual matrix, upstream reserves and facilities, feed gas quantity and quality, pipeline issues and, key design parameters and liquefaction operations for the LNG producer. The paper will also cover: direct and indirect stakeholders in the project; economics and financing; PNG-specific issues such as geography, permitting, fiscal regime, local employment opportunities, marine conditions, infrastructure and sovereign risk; LNG demand in the Pacific and LNG marketing and off-take arrangements.
Bridging the gap—the oil and gas industry
Authors: Driver Neville
Published: August 2017

The oil and gas industry is prone to skills shortages resulting from financial cycles, as is the case with many other industry sectors. Bridging the gap in indigenous employment is in part a solution to this problem and in the Northern Territory this has become easier due to innovative developments and smart partnerships.
When smart partnerships are formed that involve like-minded organisations, successful employment outcomes are inevitable. Partnerships, involving APPEA, Industries Services Training Pty Ltd (IST), the Australian Government through the National Shills Shortage Strategy (NSSS), plus the Structured Training and Employment Program—Employment Related Services (STEP ERS), which are funded through the Department of Employment Education and Workplace Relations (DEEWR) and the Department of Education and Training (DET) in the Northern Territory, have provided funding for Indigenous pre—employment training programs that are leading to positive employment outcomes in the oil and gas Industry.
The model developed and implemented in the Northern Territory by IST ensures Indigenous employment outcomes follow the delivery of the Indigenous pre-employment training programs. Key factors include:

Indigenous mentors;
culturally appropriate trainers;
Monitoring employment activities; and,
Specialist project management from APPEA and IST.

Methodologies and strategies employed by various partners ensure employment outcomes through the cooperation of principal subcontractors who require staff and who can service contracts let by major APPEA members.
Of the 18 Indigenous and Torres Strait Islander participants who commenced the eight-week program in 2008, 16 graduates received their nationally recognised Statements of Attainment at the graduation ceremony held at the Darwin Convention Centre in October 2008. There were six female graduates of the program. Competencies included first aid, dogging, safe working at heights and OHS including risk and hazard analysis training.
You may ask yourself why these courses were so successful when many others have failed. The presentation will outline difficulties; successful methodologies and strategies used by IST to ensure employment outcomes are achieved. These strategies include full-time Indigenous mentors throughout the course plus culturally appropriate trainers, smart recruitment strategies, dedicated employment service brokers soliciting employment opportunities, industry site visits, industry guest speakers and the commitment of Governments and APPEA. As a result of the successes to date, the relevant government departments have committed to further courses throughout 2009.
Optimise your Indigenous training and employment outcomes through valid, reliable, culture-fair assessment
Authors: Davidson Peter
Published: August 2017

The initial assessment process to establish appropriate training and employment pathways is critical to the recruitment of workplace candidates. Where language and cultural barriers exist—as experienced by many Indigenous candidates—the application of a suitable assessment process optimises the potential validity and reliability of the outcomes. Recently a number of organisations with Indigenous employment needs have introduced the Q Test, a language-free culture-fair instrument designed for Indigenous candidates.
The Q Test provides an insight into a candidate’s training potential, enabling companies to establish pathways based on their capacity to cope with available training programs and employment opportunities. The Q Test can reduce the potentially negative issues which may be encountered with language-based tests or un-structured interviews such as:

the perceived cultural-bias leading to resistence to recruitment processes that include any form of assessment;
the poor retention of recruits due to dissatisfaction of those who are inappropriately placed in unsuitable positions;
the resistance of line managers to embrace Indigenous employees in their crews due to previously unsuccessful placements; and,
the inherent dangers of having unsuitable employees in high risk environments.

Since 2004, ValueEdge have completed over 4,000 Q Test assessments throughout Australia and Asia. Through these assessments it has become increasingly clear that the Q Test can assist organisations to optimise their training and employment outcomes of Indigenous candidates. Within this presentation, case studies will be presented illustrating how the Q Test has positively impacted on Indigenous training and employment programs.
Dry dope-free premium connections: a zero discharge technology validated through laboratory and field testing and usage
Authors: Castiñeiras Tomás Horacio , Sakura Koji , Giacomel Bruno
Published: August 2017

Dope-free alternatives to standard thread compounds used for casing and tubing connections became commercially available around 2003. The challenges from galling resistance needs and handling and storage requirements were addressed. The lessons learnt from the initial uses and experiences with the dope-free solution were incorporated into products that are reliable and have proven their suitability in environments that vary from the extremely humid and cold North and Barents Seas to the sandy and hot environment of the Middle East. The experiences to date not only confirm the validity of initial drivers —mainly related to the environmental care—for the development of these alternatives, but also open up the possibility of the complete elimination of thread compound from the casing and tubing installation and storage processes.
The dope-free solution has demonstrated suitability for application in all tubing and casing dimensional size ranges including: all type of steels (such as common carbon steel—both API grades and proprietary), 13Cr, and corrosion resistance alloys (CRA), premium connections with metal-to-metal seal both threaded and coupled (T&C), as well as integral connections. Experience with large outside diameter (OD) semi-premium connections indicates that this can be another area of application for dope-free solutions. This paper describes the different experiences related to the field use of dry, dope-free solutions, the improvements and adjustments incorporated after initial experiences and operators feedback and the verification activities in laboratory and especially in experimental rigs under actual field conditions. The intention of this presentation is to present the advantages and the value obtained through the use of this technology.
THE SOUTH AUSTRALIAN CONTINENTAL SHELF AS A HABITAT FOR PETROLEUM
Authors: Sprigg Reg. C.
Published: August 2017

The Continental Shelf off South Australia is predicted to be a preferred habitat of petroleum. Non-metamorphosed sediments which are known or presumed to extend onto this shelf include Permian, Cretaceous and Cainozoic sediments. A single presumed Permian trough lying seaward of, and sub-parallel to, the Coorong is interpreted (aeromagnetic data) to extend to possibly 4,000 feet. As part of the Permian fossil valley system of central-eastern South Australia is is predicted to be filled by shales and sands with limited marine facies, and by glacigene sediments. The north-south orientation of the trough would require a landmass to the south from which the Permian glaciers originated. Some form of continental drift may be required to satisfy this requirement.An east-west graben or geosyncline (Gambier-Otway Basin) choked with Cretaceous mudstones and sub-greywackes projects across the shelf in the extreme south-east. Landward dips at depth extending well out beneath the shelf, may suggest a southerly boundary to the basin consistent with a pre-existing landmass in this direction.Extensive erosion at the close of Lower Cretaceous times accords with major geological change at least in more southerly shelf areas. Marine sedimentary onlap and overlap become conspicuous elements, and the accumulation of oceanward thickening sedimentary deposits is more in keeping with outbuilding terrace development. A major structural break accordingly is indicated at the end of the Lower Cretaceous, at which time development of the modern continental shelf began.The Murray River had its principal outlets in the extreme south-east zone during mid-Cretaceous to early Tertiary times, but shifted to its present position during late Cainozoic at which time its sediments were swept across the developing shelf south of Kangaroo Island. Thick sedimentary developments in each of these areas provide promising environment for petroleum generation. These are areas of extensive coastal bitumen activity.Principal petroleum prospects are to be expected within the Middle Cretaceous to Tertiary developments, but older Cretaceous and Permian deposits are potentially prospective.
CAMBRIAN AND PRECAMBRIAN PETROLEUM AN APPRAISAL
Authors: Murray Grover E.
Published: August 2017

Accumulated evidence indicates that (1) the major portion of chemical and organic evolution occurred during the 3-5 x 109 years of the earth's history preceding the Paleozoic; (2) the basic elements constituting petroleum existed in the early phases of the earth's history; (3) unmetamorphosed Precambrian and Cambrian lithic types are similar to younger ones; and (4) the population of the later Precambrian and early Paleozoic seas was relatively rich and varied, though hard skeletal parts are notably absent in the Precambrian rocks and, in all probability, were not widely developed.As petroleum is now generally considered of organic origin and is a widely disseminated and integral part of most sedimentary rocks, unmetamorphosed Precambrian and Cambrian strata should be prospective for petroleum. Discoveries of large reserves of oil in the Cambrian in parts of North Africa, Russia and the United States support this asserted prospectivity. Shows of indigenous gas in the late Proterozoic of the Amadeus Basin, Northern Territory, Australia, indicate that unmetamorphosed Precambrian strata may also yield commercial amounts of hydrocarbons.
SOME GEOPHYSICAL RESULTS ACROSS THE SIMPSON DESERT
Authors: Laherrere J. , Drayton R. D.
Published: August 2017

The subsurface geology of the Simpson Desert was unknown four years ago. Since then aeromagnetic, gravity and seismic reconnaissance surveys have been carried out by several oil companies, the B.M.R., and the South Australian Department of Mines.Two different interpretations of the aeromag data show that this method, if not very accurate with regard to the depth of basement, does give very useful indications on the present basins and trends of basement.The results of the reconnaissance helicopter gravity survey outlined the main sedimentary basins and made it possible to get the best possible location for the seismic lines, and extrapolate the seismic data, saving a lot of time and money in seismic operations.The regional features of the Simpson Desert in the Mesozoic and Upper Paleozoic units are now well known; the limits of the formations can be drawn.The 400-mile-long section across the Simpson Desert through Poeppel Corner incorporates all of the known geophysical data.To overcome the main problem of defining the depth of the Pre-Devonian unconformity, the accurate and economical technique of reflection offset shooting was evolved. Below the unconformity no real continuous events can be followed, minimising the hope of defining Lower Paleozoic problems. Some examples of seismic section and offset shooting are shown.A few stratigraphic wells on the edge of the Desert have beautifully confirmed the results of the geophysical data.The estimated cost of the geophysical data in this area is very low compared with the knowledge of the regional geology obtained from these operations. Now is the time for detailed geophysical surveys to find structures and oil, but some slides show that it is not an easy-going area.
REMARKS ON HOUGUER ANOMALY
Authors: Stackler W. F.
Published: August 2017

The different approach to gravity observations as between geodesists studying fundamental problems of the earth and geologists interested in local relationships is discussed. Attention is drawn to the significance of the variation between the geoid and spheroid in the case of gravity surveys, and discussed in terms of the results of a National Mapping Geodetic Survey in the Woomera area. The need for an Australia-wide map of the variation between geoid and spheroid is highlighted.In relation to localised gravity surveys, as in the case of oil exploration, the limitations inherent in standard Bouguer Anomaly Maps developed from semi-detailed surveys (traverses several mites apart) are analysed. The advantages gained by observing such surveys by the horizontal gradient method are outlined. Experience gained in use of this method in micro-gravity surveys is discussed.The value of the horizontal gradient method for use in obtaining observed derivatives and calculation of depth estimates is referred to. Exploitation of the horizontal gradient technique in oil exploration is recommended.