bluuebunny/crossref_metadata_2025 huggingface dataset:
SMOOTHING THE PATH—CHANGES TO COMMONWEALTH OFFSHORE PETROLEUM LEGISLATION
Authors: Pegler B. , Lautenbach J. , Richards L.
Published: August 2017

The last few years have seen a range of important changes to the Commonwealth legislation governing offshore petroleum resources. Not the least of these has been the passing of the new Offshore Petroleum Act 2006 (OPA), which will replace the Petroleum (Submerged Lands) Act 1967 (PSLA), and the recent ratification of the Treaty on Certain Maritime Arrangements in the Timor Sea (CMATS) and the Greater Sunrise International Unitisation Agreement.The PSLA has been the primary legislation for the administration of Australia’s offshore petroleum resources for close to 40 years and, through age and many amendments, it has become complex and unwieldy. The Government saw the need to rewrite the Act to provide a more user-friendly enactment that would reduce compliance costs for governments and industry. The rewrite, passed as the Offshore Petroleum Act 2006, focussed on restructuring the Act, deleting outdated text, rewriting specific sections and generally improving its readability rather than rewriting the entire Act in plain English or changing present regulatory arrangements.The OPA was passed through the Commonwealth Parliament in 2006 and has been passed as mirror legislation to cover offshore waters by the majority of States and the Northern Territory. It will be proclaimed to cover Commonwealth waters once it has been mirrored by the States. The Australian Government will continue to press the remaining States to enact the OPA and it is hoped this process can be finalised later this year.Another major step forward has been the setting up of the National Offshore Petroleum Safety Authority (NOPSA). NOPSA is the centralised Australian Government statutory authority responsible for the administration and enforcement of occupational health and safety legislation in the offshore petroleum industry. It has this role for offshore petroleum activities both in Commonwealth waters and in State and Northern Territory offshore waters. The Safety Authority commenced its regulatory operations on 1 January 2005. It has its headquarters in Perth and an office in Melbourne.
A CRITICAL ANALYSIS OF THE OFFSHORE UNITISATION REGIME IN AUSTRALIA
Authors: Soh A. , Pope C.
Published: August 2017

Unitisation, and the threat of unitisation, is a major risk for petroleum industry participants because it can significantly affect both project timelines and project profitability. Despite this, the Commonwealth legislative framework is sparse on detail regarding the process for offshore unitisation in Australia. This article examines the offshore unitisation regime in Australia and its implications. Part I describes the historical context for unitisation in Australia; Part II describes the key concepts of unitisation, including both forced unitisation and voluntary unitisation; and Part III reviews the current Commonwealth legislative framework. Part IV analyses the adequacy of the Commonwealth legislative framework in achieving efficiency in unitisation and Part V addresses recommendations for amendments to that framework.
EXPLORATION HIGHLIGHTS FOR 2006
Authors: Blevin J.E.
Published: August 2017

Key business indicators show an upward trend in exploration activity in Australia during 2006. The year was marked by fluctuating high oil prices, a strong uptake of acreage in most basins, and increased levels of drilling activity and seismic acquisition. Market demand for product, production infrastructure and the fruition of several development projects have pushed the level of exploration activity in both offshore and onshore basins. Despite this trend and the spread of tenements, almost all petroleum discoveries made during 2006 were located within 15 km of existing (but often undeveloped) fields.The Carnarvon Basin continued to be the focus of most offshore exploration activity during 2006, with the highest levels of 3D seismic acquisition and exploration/appraisal/development drilling in the country. Discoveries in the Carnarvon Basin also covered the broadest range of water depths—extending from the oil and gas discoveries made by Apache on the inboard margin of the Barrow Subbasin, to the deepwater gas discoveries at Clio–1 and Chandon–1 by Chevron. Several large gas discoveries were made in the Carnarvon and Bonaparte basins and provide significant tie-back opportunities to existing and planned infrastructure. The Bonaparte Basin also saw significantly increased levels of 2D and 3D seismic acquisition during 2006. Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition, while maintaining an overall high drilling success rate. For the first time in many years, data acquisition also occurred in frontier basins like the Daly (Northern Territory), Darling (New South Wales), Tasmanian (Tasmania) and Faust/Capel basins (Lord Howe Rise region).Coal seam methane (CSM) exploration maintained a strong performance in 2006, particularly in Queensland, while South Australia, Queensland and Victoria continue to lead the way with large tracts of acreage gazetted for geothermal energy exploration.
A network model for capture of emulsion droplets in porous media
Authors: Gao Changhong
Published: August 2017

Capture of emulsion droplets in porous media can be costly or beneficial. When produced water is injected into reservoir for pressure maintenance, the oil droplets in produced water can plug reservoir rocks and cause the well to lose injectivity. Enhanced oil recovery (EOR) technology takes advantage of this feature and plugs high-injectivity zones with emulsions. Previous studies reveal that interception and straining are the mechanisms of permeability decline. Established models rely on filtration data to determine key parameters. In this work, a network model is proposed to simulate capture of oil droplets in reservoir rocks and resultant permeability reduction. The model is validated with test data and reasonably good results are obtained. The simulation also reveals that the wettability of the tested porous media was altered by injection of emulsions. The new approach considers the characteristics of the porous media and incorporates the damage mechanisms, thus providing more scientific insights into the flow and capture of droplets in porous media.
The discovery of a new sedimentary basin: offshore Raukumara, East Coast, North Island, New Zealand
Authors: Uruski Chris , Kennedy Callum , Sutherland Rupert , Stagpoole Vaughan , Henrys Stuart
Published: August 2017

The East Coast of North Island, New Zealand, is the site of subduction of the Pacific below the Australian plate, and, consequently, much of the basin is highly deformed. An exception is the Raukumara Sub-basin, which forms the northern end of the East Coast Basin and is relatively undeformed. It occupies a marine plain that extends to the north-northeast from the northern coast of the Raukumara Peninsula, reaching water depths of about 3,000 m, although much of the sub-basin lies within the 2,000 m isobath. The sub-basin is about 100 km across and has a roughly triangular plan, bounded by an east-west fault system in the south. It extends about 300 km to the northeast and is bounded to the east by the East Cape subduction ridge and to the west by the volcanic Kermadec Ridge. The northern seismic lines reveal a thickness of around 8 km increasing to 12–13 km in the south. Its stratigraphy consists of a fairly uniformly bedded basal section and an upper, more variable unit separated by a wedge of chaotically bedded material. In the absence of direct evidence from wells and samples, analogies are drawn with onshore geology, where older marine Cretaceous and Paleogene units are separated from a Neogene succession by an allochthonous series of thrust slices emplaced around the time of initiation of the modern plate boundary.
The Raukumara Sub-basin is not easily classified. Its location is apparently that of a fore-arc basin along an ocean-to-ocean collision zone, although its sedimentary fill must have been derived chiefly from erosion of the New Zealand land mass. Its relative lack of deformation introduces questions about basin formation and petroleum potential. Although no commercial discoveries have been made in the East Coast Basin, known source rocks are of marine origin and are commonly oil prone, so there is good potential for oil as well as gas in the basin. New seismic data confirm the extent of the sub-basin and its considerable sedimentary thickness. The presence of potential trapping structures and direct hydrocarbon indicators suggest that the Raukumara Sub-basin may contain large volumes of oil and gas.
Miocene carbonate reef complexes in the Browse Basin and the implication for drilling operations
Authors: Power Michael
Published: August 2017

As Shell embarked on a new phase of exploration in permit WA–371–P a previously unrecognised drilling hazard came into focus. An exploration well intersected a high permeability zone in the Miocene Oliver Formation, which resulted in substantial losses of drilling fluids. An integrated study using newly reprocessed 3D seismic data, logs and cuttings has since shown that the well penetrated the margin of a regionally extensive carbonate reef complex. Seismic facies observed from the reprocessed data shows a remarkable array of reef morphologies, which include barrier reefs, lagoons, patch reefs and atolls. This 80 km long barrier reef system occurs directly above and parallel to the local structural hinge-lines, suggesting that a subtle inversion event may have produced a broad submerged plateau that was colonised by reef building organisms in the Miocene. These features have subsequently been drowned and buried by more than 600 m of sediment. Loss of drilling fluids whilst drilling through this section indicates that zones of high permeability are scattered throughout the reef.
Technology, investment and people: a process for extending the life of the Central Fields Complex, Gippsland Basin
Authors: Gross Michael , Abdul Rahim Abdul Aziz , Broad Erin , Grant Dean , Hargreaves Brad
Published: August 2017

The greater Central Fields complex of the Gippsland Basin, comprised of the Halibut, Fortescue and Mackerel fields, has produced 1.7 billion barrels of oil from four platforms in 37 years of production.
After the initial development drilling phases from Halibut (1969–70), Mackerel (1977–80), Fortescue (1983–86) and Cobia (1983–85) platforms and five in-fill drilling campaigns (1992–2003) it is still possible to target unswept highly productive multi-darcy reservoirs along with bypassed zones in lower quality sands.
During 2007, a six well program was completed from the Halibut platform using an upgraded workover rig that added significant volumes with combined initial rates of more than 16,000 barrels of oil per day. In addition, despite being conductor limited, the program tested strategic concepts and demonstrated significant remaining potential in a variety of reservoir qualities and depositional environments.
The outstanding success of the 2007 program was based on an up-to-date geologic framework, key technical advances, ongoing investment commitment and multi-discipline integration across workplace functions. Advancements in 3D seismic data quality and analyses, reservoir surveillance, innovative slot recovery and data integration all played a role in the success of the program.
Building on the success elements of the 2007 program, a higher capacity rig has been mobilised and upgraded to apply new drilling technologies to access the remaining potential and help mitigate basin decline.
Plate tectonic structural geology to detailed field and prospect stress prediction
Authors: Davidson John K
Published: August 2017

Arguably the first successful application of the theory of continental drift to petroleum exploration was in 1959 by the pioneers S. W. Carey and L. G. Weeks whose collaboration led to the discovery of the world class Gippsland Basin. Plate tectonics, as the theory is now known, was still nascent and not prominent during peak global oil exploration success in the 1960s. As discovery rates continue to decline, large scale description of separating and colliding continents has become increasingly impotent in the ever more complex hunt for the next barrel. Emphasis is turning from new basins and plays to smaller intra-basin discoveries related to a more detailed understanding of basin forming faults and their local stress effects on traps and trap geometries. Improved oil recovery is not only about finding new fields, but also demands detailed stress information for horizontal wellbore stability to economically and effectively increase reserves and recovery rates by extracting new oil from old fields. As a result, expensive wellbore based measurements have been deployed in the past 15 years. These precision measurements have then been averaged between wells for stress prediction but stress directions are known to vary abruptly by up to 90° over distances of less than 3 km. A solution lies in the seismic recognition of globally synchronous compressional pulses which, like a heartbeat, have added predictability of stress fields hence to stress analysis. This repetition of stress provides a workflow for stress consistent seismic interpretation that can predict horizontal and vertical changes in the direction of the maximum horizontal compressional component of a stress SH (SHD) and also in the magnitude of the stress, SHM. It is now possible to derive pre-drill at any desired point, important exploration and production variables such as stress related fault seal and open fracture orientation. Similarly, important reservoir development parameters such as fracture gradients and wellbore stability prediction will maximise recovery efficiencies and reduce development costs. This technique will also aid in effective carbon dioxide sequestration, a challenging new field of endeavour.
Water conservation at ExxonMobil facilities
Authors: Keen Gordon
Published: August 2017

As a result of Australia’s long-running drought there has been renewed community focus on water as a vital resource. In response to this and as part of ExxonMobil’s environmental performance improvement program, local water conservation teams have been established at multiple ExxonMobil Australia sites in Victoria. This has stimulated an increased focus on water as a precious resource across the entire workforce resulting in additional emphasis on pro-active planning for water conservation.
In one initiative, freshwater use at Altona Refinery was reduced by one megalitre per day. This was achieved through multiple initiatives such as optimising use of standby equipment and the frequency of flushing operations. At Long Island Point, an engineering study supported by the water conservation team identified a cost effective means of ensuring that water used in the flare-stacks is synchronised with the volume of gas being processed at the flare-tip. This initiative is on track to reduce site fresh water consumption since late February 2007 by up to 55 megalitres of potable water a year.
Since 2001 Longford has successfully reduced water use by 40% from 5 ML a day in 2001 to 3 ML a day in 2006. Similarly, 2006 water usage for Long Island Point was the lowest on record. Now, with water conservation teams firmly established on these and other sites and further projects yet to be implemented, water consumption is set to decline even further. Overall water saving initiatives have been aligned with increased regulatory and community expectations to reduce water usage, driven by the drought conditions.
Real-world decision making in the upstream oil and gas industry—prescriptions for improvement
Authors: Mackie Steve I , Begg Steve H , Smith Chris , Welsh Matthew
Published: August 2017

Business under-performance in the upstream oil and gas industry, and the failure of many decisions to return anticipated results, has led to a growing interest in the past few years in understanding the impacts of decision-making processes and their relationship with decision outcomes. Improving oil and gas decision making is, thus, increasingly seen as reliant on an understanding of the processes of decision making in the real world.
There has been significant work carried out within the discipline of cognitive psychology, observing how people actually make decisions; however, little is known as to whether these general observations apply to decision making in the upstream oil and gas industry.
This paper is a step towards filling this gap by developing the theme of decision-making process. It documents a theoretical decision-making model and a real-world decision-making model that has been distilled from interviews with many Australian upstream oil and gas professionals. The context of discussion is to review the theoretical model (how people should make decisions) and the real-world model (how people do make decisions). By comparing and contrasting the two models we develop a prescriptive list of how to improve the quality of decisions in practice, specifically as it applies in the upstream oil and gas industry.
New exploration opportunities in the southern Vlaming Sub-basin
Authors: Nicholson Chris , Borissova Irina , Krassay Andrew , Boreham Chris , Monteil Eric , Neumann Volkmar , di Primio Rolando , Bradshaw Barry
Published: August 2017

As part of the Australian Government’s Energy Security Initiative, a new tectono-stratigraphic and petroleum
systems study has been carried out in the Vlaming Sub-basin on Australia’s southwest continental margin. The study has included: biostratigraphic revisions for key wells; seismic interpretations of new and reprocessed data; geochemical assessments of key source rock intervals and liquid hydrocarbons; structural restoration of key seismic sections; and, 3D burial history modelling. Results have significantly improved our understanding of the Vlaming Sub-basin’s evolution and provide a basis for future exploration. New exploration opportunities in the southern Vlaming Sub-basin are open to explorers through the Australian Government’s 2008 Acreage Release.
Australian states and Northern Territory acreage update at APPEA 2008
Authors: Tinapple Bill
Published: August 2017

This is the annual presentation of what’s happening in onshore and coastal waters exploration in Australia’s states and the Northern Territory. The main focus of these jurisdictions’ annual report at the APPEA conference is upstream petroleum acreage opportunities. Exploration for geothermal energy resources will also be covered.
There are many and diverse exploration opportunities in onshore frontier and producing Australian basins available for explorers in 2008, including geothermal energy exploration opportunities. The number of onshore Australian acreage applications has been steadily increasing in recent years and this has resulted in higher levels of drilling and seismic acquisition, but large areas remain untouched by modern exploration.
Australian state governments continue initiatives to encourage exploration to realise their natural resource endowments including: pre-competitive basin studies; speedy and cost-effective provision of digital exploration data; provision of effective land access regimes; transparent regulatory regimes; internationally competitive royalty regimes; and, promotion of acreage releases nationally and internationally.
Production and development review 2007
Authors: Willetts Jim
Published: August 2017

Australian petroleum production was close to record levels in 2007 with higher oil production and expansion of domestic gas, LNG and coal seam gas production. Growth in coal seam gas production has reached the point where it is not only providing a significant supply source for domestic gas and power station projects, but is proposed as the source of supply to no less than four potential LNG export plants in Queensland. Five new oil and gas developments came on stream during the year. Four final investment decisions were taken on major projects, the largest being the Pluto project in the Carnarvon Basin. The pipeline of committed and potential projects now includes about 25 significant petroleum projects with a combined value of over $100 billion. Together these have the potential to significantly increase Australian production in the next five to ten years, primarily through growing gas production. In the near term significant new oil projects carry the prospect of higher oil production in 2008. Cost estimates for new projects continued to escalate sharply and skills shortages in all parts of the project delivery chain threaten the ability to deliver all of the projects as contemplated.
Intelligent fields: are we being smart enough?
Authors: Slayter Adrian
Published: August 2017

An oil company recently reported an associated value of $1.3 billion in 2006 from using intelligent technology and described it as ‘a revolution, reshaping our industry.’ A similar view is that ‘intelligent completions will become a standard practice in years to come.’
Our industry drills 80,000 wells a year; only 600 have been constructed with intelligence over the last 10 yearsâjust 0.1% of the well stock. While we are seeing a few key companies embrace this technology, which they consider to have established benefits and a good track record, others are noticeably reluctant. This paper builds on past reviews to consider potential barriers to uptake of this technology and looks at ways to address these issues.
It does this by offering constructive approaches in the areas of general understanding of the technology, to establishing candidate wells and the important process of introducing i-wells and i-fields into an organisation where success has been seen to depend on the management and mandate of the implementation team.
The following aspects of understanding are provided:

A review of the terminology;
An i-wells classification system;
Ways to manage exposure to risk;
Identifying applications;
The elements of a successful implementation team;
Some answers to frequently asked questions; and,
A review of emerging technologies.
What fuels oil company risk?
Authors: Coleman Les
Published: August 2017

This article has a simple research question: what determines the risks of oil producing companies listed in Australia and the United States, and are there any differences between their risk attitudes? A literature review is used to develop an integrated theory of company risk that is validated using a hand-collected database covering active oil and gas production companies in Australia and the United States. Risk in both countries proved to be a function of company risk propensity and risk management, which each had a small number of deep-seated drivers spread across company structure, governance and performance. These common risk-related features between companies in geographically remote countries point to the complexity of achieving portfolio diversification.
Exploration success on the North West Shelf via continuous application of seismic technologies
Authors: Thompson Mark , Bussell M Royd , Wilkins Michael , Tapley Dave , Auckland Jenny
Published: August 2017

Expansion of the North West Shelf Venture (NWSV) production infrastructure is driving plans for sequential development of the small satellite fields. The desire for additional gas reserves has fuelled increased exploration and appraisal drilling in recent years with encouraging results.
The NWSV area is a complex geologic environment with multiple play levels, petroleum systems and trapping styles. Seismic imaging is poor in many areas, primarily due to multiple contamination. In 2004, the NWSV acquired the leading edge, regional Demeter 3D Seismic Survey. Since then, continuous application of improved processing techniques, such as 3D Surface-related Multiple Elimination (SRME) and Pre-Stack Depth Migration (PreSDM), have been key to providing significant imaging enhancements. Exploration drilling based on Demeter data resulted in three significant new gas discoveries.
Pemberton–1 (2006) explored Triassic sub-cropping sands in a horst block at the southwestern end of the Rankin Trend. The well encountered an upside gas column due to the presence of intra-Mungaroo Formation shales providing a base-seal trapping geometry.
Lady Nora–1 (2007) tested the fault block west of the Pemberton horst and encountered a 102 m gross gas column with gas on rock. The upside result accelerated a near term appraisal opportunity at Lady Nora–2 (2008).
Persephone–1 (2006) drilled a down-thrown Legendre Formation dip closure in the Eaglehawk graben. Success relied on the sealing potential of the North Rankin Field bounding fault. In spite of pressure depletion associated with over 20 years of production, Persephone–1 encountered a 151 m gross gas column at virgin pressures and a different gas-water contact to North Rankin. The result demonstrated active and significant fault seal along the major North Rankin Field bounding fault.
These recent, successful exploration wells have resulted in identification of follow-up drilling opportunities and a drive for ongoing seismic imaging improvements. The discoveries have material impacts on NWSV development plans for the Greater Western Flank and in the vicinity of the Perseus, North Rankin and Goodwyn gas fields.
Evaluation of numerical modelling for a compact down-hole subsea gas-liquid separator for high gas content
Authors: Ahmed Shakil , Noui-Mehidi Mohamed Nabil , Naser's Jamal , Sanchez Soto Gerardo , Nakagawa Edson
Published: August 2017

This paper describes the computational fluid dynamics (CFD) modelling of a laboratory scale gas-liquid separator designed for high gas content. The separator consists of two concentric pipes with swirl tube in the annular space between the pipes. The gas-liquid mixture comes tangentially from the side inlet and the system works with a combination of gravity and centrifugal forces to achieve a high-efficient gas-liquid separation.
Three dimensional transient multi-phase fluid flows were solved to predict the velocity and volume fraction of each phase. The standard k- turbulence model was used for turbulence closure. The performance of the gas-liquid separator was visually established for a range of gas flow rates (271–495 L/min), with volume fraction (VF) =0.874–0.985 by observing the liquid carry over (LCO) regime where liquid was carried out in the gas stream. The liquid and gas flow rates at which the LCO was observed defines the upper operational range of the separator.
Air-water mixture was used in the numerical simulations to keep consistent with the experiments. The pressure between the inlet and exit was validated against the experiments for different air-water flow rate combinations. The values were matched reasonably well for high air flow rate (495 L/min, VF=0.985) but were under-predicted for low air flow rate (271 L/min, VF=0.874).
The air and water were mixed upstream of the inlet in the experiments and the pressure was measured at the start of the inlet. In case of numerical simulation the air and water were mixed at the inlet. This might cause the deviation of pressure when the air flow rate was low.
Effectively promoting greenhouse gas storage in Australia
Authors: Torkington John
Published: August 2017

The underground storage of greenhouse gases is seen by many as one of the primary technologies by which fossil fuel dependent nations can reduce their greenhouse gas emissions. Consequently there is a societal need to consider how best to facilitate the commercial scale uptake of this technology.
Two principal barriers remain to the commercial scale deployment of greenhouse gas storage. Existing capture technologies are very expensive and there remains community concern that the underground storage of greenhouse gases is not permanent.
It is likely that the natural gas industry will continue to be world leaders in the commercial-scale deployment of greenhouse gas storage, as this industry already captures large volumes of carbon dioxide and is familiar with underground storage technologies. In time, increased commercial scale deployment by the natural gas industry will build community confidence in the technology thus facilitating deployment by other industry sectors.
Opportunities to promote greenhouse gas storage in Australia need to be considered in the broader policy context, which should be to reduce Australia’s greenhouse gas emissions at the lowest possible cost to the community. This extended abstract reviews the various ways in which greenhouse gas storage can be promoted and tests these in light of this broader policy context. The paper identifies those opportunities that should be pursued to promote the commercial scale uptake of greenhouse gas storage and flags those opportunities that, while they might assist in the uptake, are incompatible with the broader policy objective.
Financing petroleum projects and the impact of uncertainty
Authors: Reichardt Philip , Wilcox Stuart
Published: August 2017

Financial institutions provide funding to the upstream oil and gas industry for a variety of projects including assisting with asset purchases, field appraisals and developments. Various uncertainties including reservoir, macro-economic and political variables are major considerations for financial institutions and have a considerable impact upon the type of finance offered for a project.
The primary considerations for exploration and production (E&P) companies requiring capital are the quality and stage of development of their resources. The level of resource uncertainty may be considered on a spectrum from proved developed producing reserves to contingent or prospective resources. Financial structures are designed to balance resource uncertainty with a commensurate level of return to the investor. This paper presents a brief overview of the forms of finance available, highlights how uncertainties and risks affect the type of finance provided and explores the assessment of reservoir risk through petroleum engineering and geology and geophysics.
In addition to resource uncertainty, this paper also discusses other risks including project execution, commodity prices, project costs, security coverage, the political environment and country risk, and the impact of these factors on project financing.
The paper will also touch upon various risk mitigation factors, including product hedging and political risk insurance.
Accounting and financial reporting considerations for oil and gas companies operating under Australia's proposed Carbon Pollution Reduction Scheme
Authors: Henry Nick , Cunningham Adam
Published: August 2017

The introduction of the Carbon Pollution Reduction Scheme (CPRS) is one of Australia’s most significant economic reforms since the deregulation of the Australian financial markets in the 1980s and will have a significant impact on companies across a number of sectors—in particular those in the oil and gas industry.
Given the significant greenhouse gas emission footprint of the oil and gas industry in Australia, for many oil and gas companies the cost of buying carbon pollution permits and/or reducing emissions through targetted abatement programs is likely to be significant. From a strategic perspective, understanding how the proposed CPRS could affect future cash flows will be critically important. Financial markets have already begun to factor the potential cash flow impacts into valuations of companies likely to be directly impacted by the legislation. Public disclosure of the potential impacts of the CPRS is considered both an opportunity and threat for those companies exposed to it.
The proposed CPRS will also pose significant governance, compliance and reporting challenges for those companies directly impacted by it. Measurement and reporting of emissions information will need to be subjected to the same level of control and rigour as other financial information.
This paper will examine both the immediate and longer term accounting and financial reporting considerations for oil and gas companies as a result of the CPRS, focussing on what companies need to be doing now to be prepared for the introduction of this legislation.
Recent pipeline repair tooling developments
Authors: Graham Steve
Published: August 2017

Recent events in Australia have focussed attention on the area of pipeline repair. This is historically a largely overlooked discipline, however, the results of failing to make adequate preparation may be significant. A number of tooling systems have been developed that provide intervention capability for the event of pipeline damage. In particular, several pipeline clamp designs have been developed for both high and low pressure applications, in addition to other intervention equipment. This has been supplemented by in-field experience of several of these systems. Additionally, a unique mechanical pipeline connection system for clad and lined pipes is now undergoing development.
There are a number of issues concerning pipeline repair that are particular to Australian waters including: remoteness from the main marine centres, vessel and equipment mobilisation, metocean conditions and the nature of the local pipeline infrastructure.
This presentation reviews the above concerns in light of pipeline repair philosophies and discusses the innovative technology that is being developed to assist in meeting the local challenges.
Increased earnings—using available sand monitoring instrumentation and knowledge to increase production, keeping safety issues in the driver's seat
Authors: Instanes Geir
Published: August 2017

Sand production in producing fields can be a critical safety and economic factor. The behaviour of a sand reservoir as it relates to sand production is understood to a certain degree. The sand monitors that became available in the mid-1990s made it possible to use the knowledge of sand production to manage the associated safety issues more systematically. A remarkable improvement in earnings was also observed by operators who used this knowledge in combination with the available instrumentation to find higher, but still, production rates, while still maintaining a high level of safety throughout operations.
During the last 15 years, management practice of sand production has developed significantly. Real-time sand monitors are now a standard instrument in many installations. Producing with real-time sand monitors, which feature a utilising alarm function that warns if the acceptable sand rate is exceeded, helps maintain safety and does not necessarily just maintain the highest possible production.
This paper presents field cases where a more active use of the available knowledge and data can significantly increase production, while maintaining the highest possible degree of safety.
The rise of the national oil companies and impact on Australia
Authors: Steedman Brent
Published: August 2017

The oil and gas industry is facing a period of major transition as national oil companies (NOCs) improve their operating capabilities and change their investment models
KPMG’s Global Oil and Gas Centre of Excellence has commissioned a report which analyses this changing environment, interviews senior executives from major NOCs to understand their views and offers our insights into emerging issues for the oil and gas industry.
NOCs are moving outside their national boundaries, partially privatising their assets and demanding more from potential partners and investors.
The key findings from this survey are as follows:

the growing capabilities of NOCs
the definite shift from the use of ownership to service contracts;
the success of service companies; international oil companies are responding to the changing landscape; and,
investment in people and skills is a top NOC priority.

The potential impact of the above findings on the Australian oil and gas sector are significant, and include:

reduced access to international service companies;
shortage of skills
increased opportunities for Australian service companies; and,
increased focus by international oil companies on upstream opportunities in Australia.
KPMG’s report was prepared during a period of rising oil prices. Even during the current period of price volatility, the majority of findings continue to be relevant for participants in the oil and gas industry.
The Deep Australian Water Resource Information System (DAWRIS) and the petroleum
Authors: Hostetler Stephen , Loutit Tom
Published: August 2017

The total sustainable yield of groundwater in Australia is not known even though many regions of Australia rely on groundwater for urban and rural water supply. Knowledge of deep groundwater resources is particularly poor, with little known about reservoirs below about 100 metres depth. The resource industries often discover and produce large volumes of groundwater that is subsequently evaporated, reinjected, cleaned and discharged into the ocean or streams, or supplied to urban and rural users. In addition, geothermal power and carbon capture and storage projects are also reliant on understanding groundwater processes at depth. Despite this need, Australia as a nation does not have an information system that provides data and interpretation on all groundwater reservoirs from the basement to the surface.
The Deep Australian Water Resource Information System (DAWRIS) is designed to integrate existing groundwater knowledge with previously under-utilised datasets (such as basin analysis, petroleum wells, seismic sections and geophysics) to place deep groundwater within existing government water frameworks. In addition, DAWRIS will also use technologies developed and applied within the petroleum industry to assess groundwater resources.
The challenge for DAWRIS is to build a consistent tectonostratigraphic framework (geofabric) in which to place observations on reservoir properties, groundwater sustainability and water quality. The geofabric will then act as a basis in which to predict these properties away from control points.
The petroleum industry will be able to use DAWRIS to predict the volume and quality of groundwater co-production, plan remediation and reuse strategies, and to help shape Australia’s water agenda.
Demonstrating geosequestration in Australia: the CO2CRC Otway Project
Authors: Sharma Sandeep , Cook Peter , Jenkins Charles
Published: August 2017

The CO2CRC has a demonstration storage project underway in the Otway Basin of southwest Victoria. The aim of the project is to demonstrate that carbon capture and storage (CCS) can be performed under Australian conditions.
The project involves extracting CO2 rich gas from an existing field and injecting it into a nearby depleted natural gas field for long-term storage. Injection commenced in April 2008, and approximately 100,000 tonnes of CO2 are planned to be injected through a new injection well drilled in 2007. A multi-disciplinary monitoring and verification (M&V) program has been in place from late 2005 and a baseline state of the subsurface, near surface and atmospheric conditions has been comprehensively defined prior to the commencement of injection. The project has also been instrumental in unravelling the legislative overlaps between jurisdictions and has helped shape the regulatory regime being developed by the Victorian Government.
At the present time over 35,000 tonnes of CO2 has been injected and a variety of monitoring data collected. This paper aims to provide an update on the holistic project and how some of the findings may lead to expediting commercial uptake of CCS in Australia.
Geochemistry monitoring of CO2 storage at the CO2CRC Otway Project, Victoria: operational mode
Authors: Boreham Chris , Underschultz Jim , Stalker Linda , Freifeld Barry , Kirste Dirk , Schacht Ulrike , Perkins Ernie , Ennis-King Jonathan , Dumesny Peter , Sharma Sandeep
Published: August 2017

The CO2CRC Otway Project is an Australian-first, demonstration-scale CO2 geosequestration experiment. It incorporates a wide-ranging monitoring and verification operation, including the injection of chemical tracers and the geochemical characterisation of the subsurface fluids sampled from the Naylor—1 monitoring well multi-zone U-tube system. Following the successful collection of baseline gas and fluid samples, injection began in April 2008 and by September 2008 over 20,000 tonnes of the projected total of ∼100,000 tonnes of supercritical CO2 has been injected into the depleted Waarre C unit of the Naylor gas reservoir in the Otway Basin.
Critical operational issues revolved around the timing of the chemical tracer injection at the CRC—1 injection well and the on-going maintenance and modifications to the U-tube sampling assembly. The latter resulted from two things:a hazard and operability study (HAZOP), which specifically addressed the continued integrity of the U-tube assembly and the safe collection and disposal of pressurised gases and formation waters, and the need for an innovative solution to mitigate against hydrocarbon wax precipitaton inside the U-tubes that would have jeopardise retrieval of sub-surface samples. A solvent delivery and retrieval system involving Solvesso—100TM was deployed following a mini-HAZOP. Breakthrough was initially confirmed by tracer detection at Naylor—1 approximately four months after injection began, whereas changes in the inorganic geochemical signatures were observed a few weeks later.
This has validated the sub-surface monitoring strategy and resulted in refinements to fluid flow models and expanded our understanding of geochemical processes. Furthermore, supercritical CO2 injection has resulted in the lowering of the gas-water contact at Naylor—1 and the progressive gassing out of the deeper U-tubes. Weekly to fortnightly U-tube sampling will continue until supercritical CO2 is established at Naylor—1 following which the frequency of sampling will be reviewed for the rest of the injection period.
GELTWOOD BEACH — A CASE HISTORY
Authors: Woolley J. B. , Laws R. A.
Published: August 2017

The regional geology of south eastern South Australia is briefly described; and the geophysical work which led to the discovery of a large anticline at Geltwood Beach, and to the selection of the location for the deep test.The well was drilled in the latter part of 1963 to a depth of 12,300 feet, and bottomed in Aptian sediments. After penetrating a normal Tertiary succession, the well entered a monotonous succession of sandstones, siltstones, mudstones and admixtures of the three, in which it continued to total depth. These sediments represent a dump fill of the Gambier sub-basin with terrigenous material washed in in flood quantity from the elevated basin rim.Flat dips in a vertical hole showed that the well remained on-structure to total depth.The well did not find commercial production, nor any strong shows of hydrocarbons. It gave a prospect of producible reservoirs, but left the cap rock question unsolved; it did not find any indisputable oil source rocks, nor carrier beds.The results of the reflection and refraction seismic surveys were explained.An isopach map of the Knight Group can now be drawn from which deductions can be made about the probable position of the Cretaceous wedge-out, about the structure, and very hypothetically, about a possible explanation of the marine oil seepages.
GEOPHYSICAL EXPLORATION IN THE SOUTH AUSTRALIAN PORTION OF THE MURRAY BASIN
Authors: Seedsman K. R.
Published: August 2017

Gravity and seismic surveys conducted over a number of years in the South Australian portion of the Murray Basin are discussed in chronological sequence and related to the geology. Little is known of the pre-Tertiary geology of the area from outcrop or drilling but the geophysical work suggests a development of 7,000 feet of pre-Tertiary sediments in the deepest part, north-west of Renmark. The presence of Permian in this section, interpreted from seismic refraction results has been confirmed by the drilling of A.O.G. North Renmark No. 1. Permian deposition may extend as far north-west as Canegrass Station. Gravity anomalies bear a close relationship to thickness of sedimentary section as interpreted from refraction results.
THE INITIAL MARINE TRANSGRESSION IN THE GIPPSLAND BASIN, VICTORIA
Authors: Hocking J. Barry , Taylor David J.
Published: August 2017

The Gippsland Basin of south-eastern Victoria is considered as the depositional area of Tertiary sediments lying beneath the Gippsland Plains and extending southwards beneath the Tasman Sea. This area is bounded by Mesozoic and Palaeozoic rocks.The initial marine transgression across the landward extent of the basin appears to have commenced in uppermost Eocene to lowermost Oligocene times. The nature of the initial marine Tertiary sedimentation is controlled by:four regional lower Tertiary structures—the Woodside-Seaspray Deep, the Baragwanath Anticline, the Lake Wellington Trough, and the Lakes Entrance Platform; andthe nature of the rocks upon which these sediments were deposited.Because of the progressive onlap in some areas, particularly on the Baragwanath Anticline, the initial marine transgression is diachronous.The initial marine Tertiary sediments—constituting the Lakes Entrance Formation (as redefined in this paper)—can be divided into two broad lithological units, a lower sandy one and an upper marly one. Oil traces have been recorded in the basal sands throughout the basin, particularly in the Lakes Entrance area where minor production was undertaken during the 1930s.The offshore areas of the basin appear to have the greatest oil potential. The prospective reservoir beds would be the offshore extensions of the hasal marine Tertiary sands, or else offshore marine equivalents of the Latrobe Valley Coal Measures (which underlie the marine sediments in all but the Lakes Entrance Platform area)—provided that these beds have not been flushed by artesian waters.
NEW GEOLOGICAL CONCEPTS, CASTERTON AREA, OTWAY BASIN, VICTORIA
Authors: Brown G. A.
Published: August 2017

The Casterton area of the north-west margin of the Otway Basin contains thick Mesozoic and Tertiary sediments along a shoreline composed of Cambro-Ordovician metamorphics and associated intrusives. Subsurface and structural information has been gained from two deep wells and a structure drilling programme, and from reflection and refraction seismic work. A large structure has been outlined which is at present being drilled by a third deep well, Casterton No. 1.The Mesozoic sediments are represented by an Upper Cretaceous unnamed sand unit overlying the Paaratte Formation and by the Lower Cretaceous Merino Group. The Merino sediments have been divided into seven lithological units in the Heathfield No. 1 well, the upper four of which can be correlated with intervals in the Tullich No. 1 well. Below Unit 4 is an unconformity apparent from dipmeter surveys.The Merino Group consists of mudstones, siltstones, sandstones and shales. The coarser sediments vary from lithic sandstone, through lithic greywacke to calcareous sandstone, and also include some replacement limestone. They contain considerable volcanic detritus, as well as lithic grains derived from adjacent basement areas. Plant fragments and carbonaceous materials are common. The sediments were deposited in a near-shore, shallow-water, marginal marine environment.Structurally the area has been influenced mainly by vertical tectonics. Structure drilling and refraction seismic show that this faulting is not responsible for the Kanawinka escarpment in the Casterton area. Large basement faults with a throw of up to 6,000 feet exist to the north-east of the Kanawinka escarpment.