bluuebunny/crossref_metadata_2025 huggingface dataset:
LONG-TERM CONSTRUCTION CONTRACTS—SOME ISSUES IN RELATION TO THE TAXATION OF FINANCIAL ARRANGEMENTS RULES
Authors: Murray J.H. , Miller A.K.
Published: August 2017

The Gorgon gas development project has an estimated cost of A$11 billion, the Bayu-Undan gas project has an estimated cost of A$4.2 billion and the Otway Basin gas project has an estimated cost of A$1.1 billion. The specialised equipment, technology and labour required for these costly oil and oas infrastructure projects must usually be sourced internationally and as such their costs are typically denominated in United States (US) dollars. Due to the value and long term nature of these projects, associated foreign exchange gains and losses are often significant.From an Australian income tax perspective, the treatment of foreign exchange gains and losses has been particularly uncertain and inconsistent for many years. As a result, taxation legislation in this area has recently undergone significant change. The new Taxation of Financial Arrangements legislation introduced in December 2003, has raised some complex and practically challenging concepts in relation to foreign exchange gains and losses on long term construction contracts. This paper will address two such concepts, namely forex realisation event 4 and the short-term foreign exchange rules. In particular, it will consider some of the potential compliance risk areas and how they can be managed when applying these concepts to long term construction contracts.
PETROLEUM RESOURCE RENT TAX ISSUES AFFECTING THE USE OF DEDUCTIONS
Authors: Cathro W.G.
Published: August 2017

Careful planning is necessary when buying or selling an interest in an offshore petroleum area, farming into a project or setting up operating arrangements for a project within the petroleum resource rent tax (PRRT) net, to ensure maximum use of deductions for exploration expenditure and other costs of the project.The rules dealing with transfers of interests in petroleum projects and with the transfer of undeducted exploration expenditure from an unprofitable project to a profitable one, encourage participants to ensure that they hold an interest in the relevant area before they commence exploration activity.There are special rules applying in the PRRT context to the transfer of interests in a project from one person to another. It is important to understand how these rules apply as they can impact both upon who is liable to pay PRRT on the project and the ability to use and transfer exploration expenditure.Certain head-office costs are excluded from deductibility when calculating the taxable profit of a project. The manner in which a project is structured may impact on the practical implications of this exclusion.This paper provides an overview of the PRRT regime, the implications of the transfer of an interest in a project and the requirements which must be satisfied in order to transfer exploration expenditure between projects. The paper then contains a discussion of a number of issues in relation to deductibility and use of exploration expenditure, the transfer of interests in permits and the use of contractors to undertake activities on behalf of joint venture participants maximising the scope of available deductions.
CULTURAL HERITAGE AND THE PETROLEUM INDUSTRY
Authors: Scott G.
Published: August 2017

Since the introduction of the Native Title Act 1993 (Cth) and its subsequent amendment in 1998, the main focus for developing pipeline projects was on native title issues. Cultural heritage was seen as a more operational matter and not one that would affect the ability to operate or construct pipelines. With higher standards being set by the High Court for native title claimants to maintain a claim, the management of cultural heritage issues (as opposed to the protection of native title rights) are now forming a significant part of negotiations between project proponents and indigenous groups for the development of petroleum projects.State, Territory and Commonwealth legislation dealing with Aboriginal cultural heritage also provides a more immediate source of obligations on project proponents. Even when all regulatory authorities and approvals are held, this legislation can provide affected parties the ability to stop projects if proponents ignore the requirements to protect and manage Aboriginal cultural heritage.This paper briefly examines how cultural heritage issues and native title issues interact from a practical viewpoint and then goes on to provide an overview of cultural heritage legislation throughout Australia including a focus on the unique model adopted in Queensland through the introduction of the ‘cultural heritage duty of care’.This paper then provides examples of what companies will need to do to comply with statutory obligations in minimising harm to cultural heritage through examples of common inclusions in cultural heritage management plans, together with identifying issues that are often forgotten to the detriment of a project in such plans. It also points out why cultural heritage issues may need more immediate actions in comparison with native title issues for the development and construction of new petroleum projects.
INTEGRATED MULTI-DISCIPLINARY ANALYSIS OF THE RANKIN TREND GAS RESERVOIRS NORTH WEST SHELF, AUSTRALIA
Authors: Seggie R.J. , Lang S.C. , Marshall N.M. , Cubitt C.J. , Alsop D. , Kirk R. , Twartz S.
Published: August 2017

An integrated geological study of the Rankin Trend of the North West Shelf, Australia, was undertaken to underpin the ongoing development of the giant gas fields it contains. The study applied an improved understanding ofthe regional stratigraphy in conjunction with interpretation of the regional-scale Demeter 3D seismic survey and focussed on existing fields, undeveloped discoveries, and exploration prospects. The study included a redescription of 1,500 m of core, a new facies-based petrological analysis, a revision of the well-based stratigraphy and palaeogeographic mapping, and a seismic stratigraphic analysis. Reservoir production and hydrodynamic data were also integrated. The stratigraphic framework was improved by implementing a broad range of depositional and facies analogues and a system-wide sequence stratigraphic approach to understanding lateral and vertical stacking patterns of the reservoir succession. Visualisation and modelling technologies were also employed to more adequately describe genetic reservoir packages.Specific outcomes include: improved correlation of reservoir sequences, application of appropriate subsurface depositional analogues to field descriptions, updated palaeogeographic maps and recognition of palaeosols as stratigraphic marker horizons—resulting in a more consistent regional interpretation framework. This forms the basis for seismic stratigraphic interpretation away from well control.The new regional geological model has enabled the linkage of exploration, development and production understanding across the North West Shelf assets as well as management of geological uncertainties.
INTEGRATION OF RESERVOIR AND WELL FLOW SIMULATORS FOR ANALYSIS OF HORIZONTAL WELL PERFORMANCE
Authors: Sanchez G. , Kabir A. , Nakagawa E. , Manolas Y.
Published: August 2017

The optimisation of a well’s performance along its life cycle demands improved understanding of processes occurring in the reservoir, near wellbore and inside the well and flow lines. With this purpose, the industry has been conducting, for several years, initiatives towards reservoirwellbore coupled simulations.This paper proposes a simple way to couple the near wellbore reservoir and the wellbore hydraulics models, which contributes to the optimisation of well completion design (before and while drilling the well) and the maximisation of the well inflow performance during production phases, with support of real-time and historical data. The ultimate goal is the development of an adaptive (self-learning) system capable of integrated, real-time analysis, decision support and control of the wells to maximise productivity and recovery factors at reservoir/field level. At the present stage, the system simulates the inflow performance based on an iterative algorithm. The algorithm links a reservoir simulator to a hydraulics simulator that describes the flow inside the wellbore. The link between both simulators is based on equalisation of flow rates and pressures so that a hydraulic balance solution of well inflow is obtained. This approach allows for full simulation of the reservoir, taking into consideration the petrophysical and reservoir properties, which is then matched with the full pressure profile along the wellbore. This process requires relatively small CPU time and provides very accurate solutions. Finally, the paper presents an application of the system for the design of a horizontal well in terms of inflow profile and oil production when the production is hydraulically balanced.
SHEAR DILATION DIAGNOSTICS—A NEW APPROACH FOR EVALUATING TIGHT GAS STIMULATION TREATMENTS
Authors: Chipperfield S.T. , Wong J.R. , Warner D.S. , Cipolla C.L. , Mayerhofer M.J. , Lolon E.P. , Warpinski N.R.
Published: August 2017

Many tight gas reservoirs require fracture stimulation to achieve commercial outcomes. These reservoirs can often be characterised geologically and geomechanically by high deviatoric stresses and hard, naturally fractured rock. Stimulation treatments in such reservoirs may create complex fracture networks from a combination of shear and tensile failures. Water fracs can be used where shear failure is anticipated to dominate; however, in these environments few practical modelling tools exist to determine: the level of permeability enhancement; the degree of permeability retainment during draw-down; and, the stimulated rock volume (SRV). This paper seeks to provide the engineer with a suite of tools capable of achieving these goals.This paper presents a dual porosity, pressure-dependent permeability reservoir simulation model that was devised to honour shear failure mechanisms (also called shear dilation) using basic geological characterisation. The assumptions of this model and the pragmatic selection of first-order effects are discussed. Using the results of this simulation model, three families of diagnostic tools are presented. The first category is that of treatment diagnostics, which includes bottom hole pressure evaluation, injectivity and fall-off analysis. The second approach is called seismic-based reservoir characterisation (SBRC), which uses the microseismic to determine the SRV as well as provide estimates of the initial and stimulated fracture network properties. The third category is post-treatment diagnostics, which incorporates the evaluation of pressure draw-down characteristics.Finally, this paper compares these individual approaches and provides a workflow to evaluate data on future wells.
AUSTRALIA’S FIRST GEOSEQUESTRATION DEMONSTRATION PROJECT—THE CO2CRC OTWAY BASIN PILOT PROJECT
Authors: Sharma S. , Cook P. , Berly T. , Anderson C.
Published: August 2017

Geological sequestration is a promising technology for reducing atmospheric emissions of carbon dioxide (CO2) with the potential to geologically store a significant proportion Australia of Australia’s stationary CO2 emissions. Stationary emissions comprise almost 50% (or about 280 million tonnes of CO2 per annum) of Australia’s total greenhouse gas emissions. Australia has abundant coal and gas resources and extensive geological storage opportunities; it is therefore well positioned to include geosequestration as an important part of its portfolio of greenhouse gas emission mitigation technologies.The Cooperative Research Centre for Greenhouse Gas Technologies is undertaking a geosequestration demonstration project in the Otway Basin of southwest Victoria, with injection of CO2 planned to commence around mid 2007. The project will extract natural gas containing a high percentage of CO2 from an existing gas well and inject it into a nearby depleted natural gas field for long-term storage. The suitability of the storage site has been assessed through a comprehensive risk assessment process. About 100,000 tonnes of CO2 is expected to be injected through a new injection well during a one- to two-year period. The injection of CO2 will be accompanied by a comprehensive monitoring and verification program to understand the behaviour of the CO2 in the subsurface and determine if the injected carbon dioxide has migrated out of the storage reservoir into overlying formations. This project will be the first storage project in Australia and the first in the world to test monitoring for storage in a depleted gas reservoir. Baseline data pertinent to geosequestration is already being acquired through the project and the research will enable a better understanding of long-term reactive transport and trapping mechanisms.This project is being authorised under the Petroleum Act 1998 (Victoria) and research, development and demonstration provisions administered by the Environment Protection Authority (EPA) Victoria in the absence of geosequestration- specific legislation. This highlights the need for such legislation to enable commercial-scale projects to proceed. Community acceptance is a key objective for the project and a consultation plan based on social research has been put in place to gauge public understanding and build support for the technology as a viable mitigation mechanism.
MARINE ZONE MANAGEMENT AND THE EPBC ACT—HOW ENVIRONMENTAL MARINE GEOLOGICAL INFORMATION PROVIDES CERTAINTY FOR PETROLEUM EXPLORATION
Authors: Harris P.T. , Heap A. , Post A. , Whiteway T. , Potter A. , Bradshaw M.
Published: August 2017

To protect the diversity of marine life in Australia’s Exclusive Economic Zone (EEZ), the federal parliament has passed the Environmental Protection and Biodiversity Conservation (EPBC) Act 1999. The Act is being implemented through the design of a national representative system of marine protected areas (MPAs) that will place under protection a representative portion of Australia’s EEZ by 2012. There have already been 13 MPAs nominated for the southeast region in 2006.Limited biological data in Australia’s EEZ has resulted in biophysical information compiled by Geoscience Australia being used as a proxy for seabed biodiversity in support of marine conservation planning. Information we use to characterise the seabed includes bathymetry, geomorphology, acoustic properties, sediment properties, and slope and sediment mobilisation due to waves and tides. To better characterise habitats on the Australian continental shelf, Geoscience Australia is creating seascape maps (similar to geological facies maps) that integrate these multiple layers of spatial data, and which are useful for the prediction of the distribution of biodiversity in Australia’s EEZ. This information provides 100% spatial coverage based on objective, multivariate statistical methods and offers certainty for managers and stakeholders including the oil and gas industry, who are involved with designing Australia’s national MPA system. Certainty for industries operating in the EEZ is enhanced by a reproducible, science-based approach for identifying conservation priorities and the classification of sea floor types within multiple use areas.
THE EMERGING MARKET IN CARBON CREDITS IN AUSTRALIA
Authors: Warburton A.M. , Singleton S.E.
Published: August 2017

Climate change policy in Australia is in a state of upheaval.The Federal Government, after years of opposing mandatory carbon constraints, has changed tack and is now investigating emissions trading as a possible means of reducing greenhouse gas emissions.With a federal election looming, the Labor Opposition has committed to ratifying the Kyoto Protocol and reducing greenhouse gas emissions by 60% (against 1990 levels) by 2050. Not to be left out, the State governments say they will introduce an emissions trading regime themselves, if the federal government of the day does not move quickly enough.It now seems clear that there will be some form of carbon price signal in Australia within the next five to 10 years. What is unclear is the form that the carbon constraints might take.Amid this policy uncertainty, large energy producers and users are starting to invest in emissions reduction projects in Australia, as a form of risk management for potential future carbon liabilities. These projects are unusual in that the carbon rights that are being traded are not recognised under any existing Australian statutory scheme, nor are they part of the Kyoto mechanisms. Consequently, they are not recognised by law and do not have any real value today. Their value is largely potential future value under some form of emissions trading scheme or carbon tax regime (which places a price on carbon emissions).These projects raise some novel issues for project developers and purchasers. What is the carbon right that is being sold? How do you frame it to maximise flexibility for use under a future carbon constraint regime?How do you ensure ongoing validity of the carbon right for an indefinite period into the future? For carbon sink projects, the purchaser will want some comfort regarding permanence of abatement of CO2 emissions.Project developers are often small start-up companies with few assets and limited cash flow. They may not be in a position to offer securities for performance. What mechanisms can a purchaser use to assist with start-up funding and also secure the rights they are purchasing?What pricing structures are available, particularly for future sales, against the background of a possible future carbon market?What obligations should the developer/seller have in relation to verification, monitoring and reporting of avoided emissions?How might projects be structured to involve multiple buyers to support the project and facilitate development of a market?
WATER AND THE COAL SEAM GAS INDUSTRY
Authors: Scott G. , Ammundsen C.
Published: August 2017

Access to water is a significant issue in Queensland as much of the State continues to be affected by a prolonged drought. Coal seam gas production involves extracting water from coal seams to reduce the groundwater pressure that keeps the methane trapped in the coal. This process produces large volumes of water. Local councils, primary producers and industrial developers are potential end users of this water; however, if the water is of poor quality, it may be unsuitable for release in the environment and for other direct beneficial uses.This paper examines the complex legislative and regulatory hurdles that need to be overcome before any mutually beneficial agreement between the coal seam gas producer and end user may be completed. It also examines an operational policy recently released by the Queensland Environmental Protection Agency that proposes a framework for the regulation and management of water extracted from coal seams.
PESA PRODUCTION AND DEVELOPMENT REVIEW 2006
Authors: Bethune Graeme
Published: August 2017

The Australian petroleum industry is having considerable success in offsetting natural field decline through new developments in existing basins and projects in new basins. The industry is also having great success with less conventional coal seam methane production. In energy terms Australian petroleum production peaked in 2000, and then fell until 2003 due to falling oil production. Since then, and despite continuing falls in oil and liquids production, total production has been increasing towards the 2000 peak. In 2006 eight new developments came into production: Darwin LNG, three oil and four gas developments. Seven of these developments were in new basins. Looking to the future there are now more than 20 significant petroleum projects with a combined value of more than A$50 billion either committed or being considered. Between them these could significantly increase Australian production in the next five years, primarily through growing gas production. Replacing falling oil production remains a challenge, as does managing cost increases and skills shortages generally.
Simulation of reservoir permeability decline due to invasion of large particles
Authors: Gao Changhong
Published: August 2017

Particles can deposit in reservoir rocks and cause severe damage to their permeabilities. The mechanisms of permeability decline are attributed to adsorption, size exclusion and gravity settling of particles in porous media. Previous test results reveal that high particle concentration, low fluid velocity, large particle size lead to more damage. Traditional models are empirical correlations heavily dependent on core test data.
In this paper, a network model incorporating the damaging mechanisms is used to study capture of large (non-Brownian) particles in porous media and resultant permeability damage. The model employs certain assumptions to imitate the characteristics of real porous media. The proposed procedure applies force analysis to obtain particle invasion depth, and determines damaging mechanisms by pore size to particle size ratio. The model assumes that for a particle much smaller than the pore where it is captured, surface deposition is the mechanism for permeability decline. For particle size comparable to pore size, pore throat plugging and bridging are the causes of permeability damage. The method is validated with test data and reasonably good results are obtained. The new model provides more insights into the deposition process and does not rely on core flooding data.
A sand management system for mature offshore production facilities
Authors: McKay Ian , Russ Paul , Mohr Jack
Published: August 2017

ExxonMobil subsidiary Esso Australia Pty Ltd has implemented a sand management system to minimise the impact of sand to its operations in the Bass Strait. Some of these facilities have been in operation for more than 30 years and no downhole sand control was installed during original drilling completions. Over time, with increased water production, sand production has become more problematic.
This paper examines the strategies used to minimise the impact of sand production on facilities including the impact of corrosion and erosion on downhole, offshore topsides, pipeline and onshore plant infrastructure. The sand management system includes detailed operational instructions for flowing wells, monitoring sand production, and installing retrofit sand control where required. The system also defines a management structure with assigned responsibilities to ensure that operational guidelines are followed and continuous improvement opportunities are implemented.
Drilling success as a result of probabilistic lithology and fluid prediction—a case study in the Carnarvon Basin, WA
Authors: Lamont Matthew , Thompson Troy , Bevilacqua Carlo
Published: August 2017

The aim of quantitative interpretation (QI) is to predict lithology and fluid content away from the well bore. This process should make use of all available data, not well and seismic data in isolation. Geological insight contributes to the selection of meaningful seismic attributes and the derivation of valid inversion products. Uncertainty must be taken into account at all stages to permit risk assessment and foster confidence in the predictions. The use of the Bayesian framework enables prior knowledge, such as a geological model, to be incorporated into a probabilistic prediction, which captures uncertainty and quantifies risk.
Nostradamus is a fluid and lithology prediction toolkit that forms part of a comprehensive QI workflow. It utilises a Bayesian classification scheme to make quantitative predictions based upon inverted seismic data and depth-dependent, stochastic rock physics models. The process generates lithology and fluid probability volumes. All available information is combined using geological knowledge to create a realistic pre-drill model. Separately, stochastically modelled multidimensional crossplots, which account for the uncertainty in the rock and fluid properties (based on petrophysical analyses of well data), are used to build probability density functions such as acoustic impedance (AI) vs Vp/Vs and LambdaRho vs MuRho. These are then compared to crossplots of equivalent inverted data to make predictions and quantitatively update the geological model. Individual probability volumes as well as a most-likely lithology and fluid volume are generated. This paper presents a case study in the Carnarvon Basin that successfully predicts fluids and lithologies away from well control in a way that effectively quantifies risk and reserves. Two of the three successful gas exploration wells were drilled close to dry holes.
Sedimentary fill of submarine canyons and channels using a Cellular Automata process-based model
Authors: Salles Tristan , Cacas Marie-Christine , Mulder Thierry , Li Fangjun , Griffiths Cedric , Dyt Chris
Published: August 2017

Understanding the deposition processes in submarine canyons and channels has significant implications for petroleum exploration. A numerical model has been established to simulate the sedimentary fill of canyons and channel-levee complexes present in turbiditic environments. The model is based on a Cellular Automata (CA) approach. Depositional processes which control the evolution of the system are described by the rules established either empirically from observations or from simplified physical laws. Sedimentary systems are described by a meshed domain and are built with a series of unitary events. Two versions have been developed and couple the impact of flow effects on the nature and architecture of deposits.
The first model allows a dynamic description of seabed evolution under the activity of gravity flows. For a single event simulation, both the morphology of the seabed and sediment distribution is estimated at each time step. The model was calibrated by the application to the turbulent surge that occurred during the 1999 storm in Capbreton canyon (France) using core control.
The second model simulates deposit architecture accumulated by a succession of steady state flows. A possible way to average physical processes over time is to then consider geological events such as successive quasi-steady state flows for which sediment transport has permanent values. The CA paradigm is an efficient approach to quickly obtain such stationary states. Results obtained for the first sequence of the Pab channel complex (Indo-Pakistani margin) provides the first step towards the quantitative understanding of external parameters on catastrophic gravity flow dynamics and on the organisation of subsequent deposits.
Closed loop glycol systems—experience from BP's Shah Deniz gas export project and advances in technology
Authors: Condilis Anthea , Vale Jon Even , Stranna Tor-Erik
Published: August 2017

Aker Kværner Process Systems (AKPS) in Norway provided the monoethylene glycol (MEG) regeneration unit for BP’s Shah Deniz Gas Export Project. Design by AKPS began in 2003. The MEG unit was installed by May 2006 at the Sangachal Terminal outside Baku, Azerbaijan. MEG injection was selected to prevent hydrate formation in the pipelines conveying gas and condensate from the Shah Deniz gas field in the Caspian Sea to the onshore terminal. This MEG unit employs full stream reclamation, where reclamation (salts removal) is integrated into the reconcentration process (water removal).
The commissioning of this MEG unit by BP was completed by November 2006 and the start-up phase was complete by May 2007. The chemistry of the MEG system was evaluated by AKPS during this period. Improved understanding of the chemistry has led to advances in the design of subsequent MEG units by AKPS.
Two fundamental improvements are proposed for future MEG unit designs. One fundamental improvement is the use of a slip stream reclaimer for salts removal. Consequently, the reconcentration operation is not dependent on the operation of the reclaimer, greatly improving the availability and flexibility of the system. Another consequence of slip stream reclamation is the significant reduction in size of the reclaimer, and with this comes reduced capital investment and improved maintainability.
The second fundamental improvement is the inclusion of pre-treatment operations for controlled precipitation and removal of low solubility salts originating from formation water and pipeline corrosion. Together with careful consideration of chemical additions to facilitate this precipitation, this design improvement is expected to prevent scaling in the downstream equipment. The function of the reclaimer is primarily to remove high solubility salts (chlorides).
Improvements in the design of MEG regeneration units that are described above and the motives behind them are explored in detail.
Disclosure dilemmas: disclosure issues in the Australian energy and resources sector
Authors: Reed Simon
Published: August 2017

In light of the continuing buoyancy in commodity and energy prices and the related spike in mergers and acquisitions activity in the energy and resources sector, energy and resources companies’ disclosure obligations are coming under closer scrutiny, both during merger talks and in the ordinary course of business.
Company directors and officers need to have a sound understanding of their disclosure responsibilities, so that they can navigate the disclosure minefield with confidence during important periods of growth and consolidation for their company and the sector in general.
This paper will highlight key risks and considerations that energy and resources companies should be aware of when considering their disclosure obligations.
A better understanding of several specific disclosure situations is provided, including:

the enforcement regime that applies to energy and resources companies in relation to disclosure issues (including liability for individual directors and officers);
disclosure obligations during merger discussions;
appropriate disclosure responses when a bidder comes knocking;
difficulties in providing information to prospective bidders;
the application of ASX disclosure carve-outs to merger discussions—when they cease to apply;
potential insider trading issues in a takeover context;
the impact of joint venture arrangements on disclosure obligations; and,
specific disclosure obligations for energy and resources companies and proposed changes to oil and gas reporting.
Several recent incidents and prosecutions relating to public disclosure issues in the sector are examined to provide a clearer idea of the risks relating to non-disclosure or late disclosure.
Discovering Australia's future petroleum resources: the strategic geoscience information role of government
Authors: Powell Trevor G
Published: August 2017

Australia’s production of oil is in steady decline. Given the maturity of the oil producing areas, only the discovery of a significant new oil province can arrest the long-term decline in Australian production. Moreover, the increase in demand for clean energy and the location of Australia’s major gas reserves means additional gas resources are also desirable. Many sedimentary basins both onshore and offshore are under-explored and are classed as exploration frontiers. Only Australian national, State and Territory governments, acting jointly or severally in partnership with the private sector, can ensure that the petroleum resource endowment of these frontiers is appropriately explored and developed to the benefit of the nation. As a nation, Australia needs to know the extent of this resource endowment.
A major barrier to the exploration of these frontier basins is the absence of sufficient basic geological information to allow exploration investors to make well-informed decisions. Understanding prospectivity is a primary consideration for explorationists, but such assessments are fundamentally dependent upon an infrastructure of geoscience data, concepts and knowledge which provide the framework of successful exploration. The absence of information means high risk and reduces the possibility of investment in exploration in frontier basins. For exploration frontiers the basic geological information collected by State and national geological surveys is fundamental to informed decision-making by exploration companies.
Australia competes with other nations for global exploration investment. Given the sovereign rights to the resource and the importance of oil and gas to the nation’s economy and security, provision of pre-competitive geoscience information by government is an effective way of attracting exploration investment to Australia. However, the supply of pre-competitive geoscience data—which includes ready access to pre-existing industry data and information—is a strategic enterprise that must be maintained for many years if it is to serve the needs of the nation and the industry through the long lead and cycle times inherent in the exploration and production cycle. Promotion of successful exploration is dependent on the maintenance of a competitive exploration environment that includes the free flow of relevant information in forms that meet the need of all market players. Australia has excellent examples of strategies and case histories where provision and promotion of geoscience information has been effective in attracting significant exploration investment.
Exploration highlights for 2007
Authors: Krassay Andrew , Blevin Jane , Cathro Donna
Published: August 2017

Record-high oil prices along with on-going development of infrastructure, increasing domestic demand and international LNG sales continued to drive significant investment in exploration in onshore and offshore Australia during 2007. These trends are reflected nationally by strong uptake of acreage and continued high levels of drilling activity and seismic acquisition. Overall, drilling and discovery trends were similar to 2006 which showed significant exploration activity focussed on proven hydrocarbon basins (Carnarvon, Browse, Perth and Cooper basins). Most petroleum discoveries made in 2007 were located within 10 to 15 km of existing fields.
In terms of number of exploration wells, the offshore Carnarvon continued to dominate with over 20 new field wildcats drilled. Discoveries include a major deep-water gas find for BHP-Billiton at Thebe-1 on the outer Exmouth Plateau, Apache’s gas finds at Brunello–1, Julimar–1 and Julimar East–1, oil for Santos at Fletcher–1 and gas at Lady Nora–1 for Woodside. The Browse Basin saw a significant increase in drilling activity with some success. Exploration in the offshore southwest margin received a major boost with a series of shallow-water discoveries for ROC Oil in the Perth Basin with gas at Frankland–1 395and Perseverance–1 and gas and oil at Dunsborough–1.
Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition. This activity resulted in numerous small to moderate oil discoveries for Santos, Beach Petroleum, Eagle Bay Resources, Stuart Petroleum and Victoria Petroleum. There were a few notable exceptions to near-field exploration in 2007 with several wildcats drilled in frontier regions including PetroHunter Energy and Sweetpea Petroleum’s Shanendoah–1 in the Georgina/Betaloo basins, Austin’s Gravestock–1 in the onshore Stansbury Basin and the onshore drilling campaign by ARC Energy in the Canning Basin. In Queensland, CSM exploration and discovery continued to experience strong positive growth underpinned by delivery to local markets.
To SSIV, or not to SSIV: that is the question
Authors: Cooper Steven , Aoun Fiona
Published: August 2017

Sub Sea Isolation Valves (SSIVs) are normally considered for installation on the majority of facility builds. They first started coming to prominence in the world of safety following the Piper Alpha tragedy in 1988, where 167 people died and the platform was destroyed as a result of an explosion and fire.
The aim of SSIVs is to protect the people on the platforms by limiting the amount of hydrocarbon available for a jet fire. Reducing the severity of a jet fire protects the integrity of manned living quarters in the event of an issue with the pipeline. This theory still holds true today but twenty plus years on SSIVs are not always included in new facility designs.
Oil and gas fields developed in the future are more likely to be in more remote locations with large diameter pipelines tied back to onshore processing facilities. With well bays being replaced by subsea wells and flowlines it would be thought that the SSIV would now be man’s best friend; however, with the oil and gas industry showing a declining trend in fatalities around the world and with design improvements preventing and mitigating the occurrence of major accident events, many operators are questioning the added benefits of the SSIV.
This paper debates the use of the SSIV and explores the issues over which many design teams deliberate. It considers the positives and the negatives associated with the SSIV and illustrates why an SSIV installation is a case-by-case prospect. A case study using a risk-based approach for installing the SSIV as part of a design concept is used to help illustrate this point.
Carbon capture and storage—deelopments in Australia
Authors: Barrymore Stuart , Mathison Ann-Maree
Published: August 2017

Legal and non-legal developments in the carbon capture and storage (CCS) arena continue to gain momentum in Australia. On 22 November 2008 the Offshore Petroleum Amendment (Greenhouse Gas Storage) Act 2008 (Cth) (GGS Amendments) came into force. The GGS Amendments follow the amendment in February 2007 of the Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter 1972 and 1996 Protocol Thereto (London Protocol) which allows the storage of carbon dioxide under the seabed.
The GGS Amendments amend the Offshore Petroleum Act 2006 (Cth) (OPA), which has now been renamed the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth) (Act), to establish a system of offshore titles that authorises the transportation, injection and storage of greenhouse gas (GHG) substances in geological formations under the seabed and manage the inevitable interaction with the offshore petroleum industry. In addition, the States of Queensland and Victoria have now enacted onshore CCS legislation.
In September 2008, the Federal Government announced $100 million in funding for an Australian Global Carbon Capture and Storage Institute (AGCCSI), which will be an international hub for co-ordinating public and private sector funding of CCS research projects and will provide international policy and management oversight. The AGCCSI was formally launched on 16 April 2009. The goal of the AGCCSI is to deliver at least 20 commercial scale CCS plants around the world by 2020. There are numerous examples in Australia and internationally of CCS pilot projects underway with the goal of deploying CCS on a commercial scale. The Callide Oxyfuel Project in Central Queensland that began construction recently will retrofit an existing coal fired power station with a CCS facility, with plans for the oxyfuel boiler to be operational in the Callide A power plant by 2011.
The Hermes oil field: a small field takes wings
Authors: Smith Greg C , Louis Jai , White Roy , Gupta Ritu , Collinson Roger
Published: August 2017

The Lambert field was discovered in 1973 with oil reservoired in Tithonian turbidites. It was viewed as uneconomic until 1996 when re-evaluation led to discovery of the adjacent Hermes oil accumulation by Lambert–2. The Lambert–3 producer was drilled nearby to Lambert–2 in 1997 and tied back to the Cossack-Pioneer floating production storage offloader (FPSO). Lambert–3 was expected to drain about 25 MMBBLs of oil, coming off plateau after one year and declining substantially thereafter; however, it had produced more than 52 MMBBLs of oil by late 2008 without any water cut and may produce much more in the next 15–20 years. In contrast, several appraisal and production wells drilled since in the adjacent Lambert accumulation have only produced modest recoveries. Why were the original deterministic views of the Lambert-Hermes field so far from present estimates?
This paper describes the approach taken to re-assess the Lambert and Hermes oil accumulations. First, the traps were reviewed by framing the main uncertain variables followed by a rigorous scenario analysis of the field. The work was expedited by using a statistical design to substantially reduce the number of scenarios required for modelling and simulation. The results included a statistical analysis and produced a better view of the probable reserves ranges.
Remarkably, after 11 years’ production the field potential warranted re-appraisal. The scenario analysis indicated which uncertain variables needed attention and helped to select well locations. The results of appraisal should decide between several re-development options. The main possibilities for new field development include: drilling of additional oil producers; water shut-off in some producers; an additional flow-line to de-bottleneck oil production from Lambert and Hermes; re-instatement of a gas-injection line for gas-lift of wells at high water-cut; and installation of a new manifold further north in the Hermes accumulation to optimise field recovery.
A pre-cursor extensive Miocene reef system to the Rowley Shoals reefs, Western Australia: evidence for structural control of reef growth or natural hydrocarbon seepage?
Authors: Ryan Georgina , Bernardel George , Kennard John , Jones Andrew T , Logan Graham , Rollet Nadege
Published: August 2017

Numerous Miocene reefs and related carbonate build-ups have been identified in the Rowley Shoals region of the central North West Shelf, offshore Western Australia. The reefs form part of an extensive Miocene reef tract over 1,600 km long, which extended northward into the Browse and Bonaparte basins and southward to North West Cape in the Carnarvon Basin—comparable in length to the modern Great Barrier Reef. Growth of the vast majority of these Miocene reefs failed to keep pace with relative sea-level changes in the latest Miocene, whereas reef growth continued on the central North West Shelf to form the three present-day atolls of the Rowley Shoals: Mermaid, Clerke and Imperieuse reefs.
In the Rowley Shoals region, scattered small build-ups and local reef complexes were first established in the Early Miocene, but these build-ups were subsequently terminated at a major Mid Miocene sequence boundary. Widespread buildups and atoll reefs were re-established in the Middle Miocene, and the internal stacking geometries of the reefs appear to relate to distinct growth phases that are correlated with eustatic sea-level fluctuations. These geometries include: a basal aggradational buildup of early Middle Miocene age; a strongly progradational growth phase in the late Middle to early Late Miocene that constructed large reef atolls with infilling lagoon deposits; and a back-stepped aggradational growth phase that formed smaller reef caps in the early–latest Late Miocene.
Growth of the majority of the reefs ceased at a major sea-level fall in the Late Miocene (Messinian), and only the reefs of the present-day Rowley Shoals (Mermaid, Clerke and Imperieuse reefs, as well as a drowned shoal to the southwest of Imperieuse Reef) continued to grow after this event. Growth of the Rowley Shoals reefs continued to keep pace with Pliocene-Recent sea-level changes, whereas the surrounding shelf subsided to depths of 230–440 m.
We conclude that initial reef growth in the Rowley Shoals region was controlled by transpressional reactivation and structuring of the Mermaid Fault Zone during the early stage of collision between the Australian and Eurasian plates. During this structural reactivation, seabed fault scarps and topographic highs likely provided ideal sites for the initiation of reef growth. The subsequent growth and selective demise of the reefs was controlled by the interplay of eustatic sea-level variations and differential subsidence resulting from continued structural reactivation of the Mermaid Fault Zone. In contrast to models proposed in other regions, there is no direct evidence that active or palaeo hydrocarbon seepage triggered or controlled growth of the Rowley Shoals reefs or their buried Miocene predecessors.
What we know (and what we don't) about the petroleum prospectivity of the Northland Basin, North Island, New Zealand
Authors: Uruski Chris
Published: August 2017

The offshore Northland Basin is a major sedimentary accumulation lying to the west of the Northland Peninsula of New Zealand. It merges with the Taranaki Basin in the south and its deeper units are separated from Deepwater Taranaki by a buried extension of the West Norfolk Ridge. Sedimentary thicknesses increase to the northwest and the Northland Basin may extend into Reinga. Its total area is at least 65,000 km2 and if the Reinga Basin is included, it may be up to 100,000 km2.
As in Taranaki, petroleum systems of the Northland Basin were thought to include Cretaceous to Recent sedimentary rocks. Waka Nui–1 was drilled in 1999 and penetrated no Cretaceous sediments, but instead drilled unmetamorphosed Middle Jurassic coal measures. Economic basement may be older meta-sediments of the Murihiku Supergroup. Thick successions onlap the dipping Jurassic unit and a representative Cretaceous succession is likely to be present in the basin. Potential source rocks known to be present include the Middle Jurassic coal measures of Waka Nui–1 and the Waipawa Formation black shale. Inferred source rocks include Late Jurassic coaly rocks of the Huriwai Beds, the Early Cretaceous Taniwha Formation coaly sediments, possible Late Cretaceous coaly units and lean but thick Late Cretaceous and Paleogene marine shales.
Below the voluminous Miocene volcanoes of the Northland arc, the eastern margin of the basin is dominated by a sedimentary wedge that thickens to more than two seconds two-way travel time (TWT), or at least 3,000 m, at its eastern margin and appears to have been thrust to the southwest. This is interpreted to be a Mesozoic equivalent of the Taranaki Fault, a back-thrust to subduction along the Gondwana Margin. The ages of sedimentary units in the wedge are unknown but are thought to include a basal Jurassic succession, which dips generally to the east and is truncated by an erosional unconformity. A southwestwards-prograding succession overlies the unconformity and its top surface forms a paleoslope onlapped by sediments of Late Cretaceous to Neogene ages. The upper succession in the wedge may be of Early Cretaceous age—perhaps the equivalent of the Taniwha Formation or the basal succession in Waimamaku–2.
The main part of the basin was rifted to form a series of horst and graben features. The age of initial rifting is poorly constrained, but the structural trend is northwest–southeast or parallel to the Early Cretaceous rifting of Deepwater Taranaki and with the Mesozoic Gondwana margin.
Thick successions overlie source units which are likely to be buried deeply enough to expel oil and gas, and more than 70 slicks have been identified on satellite SAR data suggesting an active petroleum system. Numerous structural and stratigraphic traps are present and the potential of the Northland Basin is thought to be high.