bluuebunny/crossref_metadata_2025 huggingface dataset:
A TECHNICAL APPRAISAL OF STORAGE OF GORGON CO2 AT BARROW ISLAND, NORTH WEST SHELF
Authors: Malek R. , Bartlett R. , Evans B.
Published: August 2017

The Gorgon gas field lies 70 km west of Barrow Island in 200 m of water. The field is jointly owned by ChevronTexaco Australia, Shell Development Australia and Mobil Exploration and Producing Australia and has certified proven hydrocarbon gas reserves of 272.69 Giga cubic metres (Gm3) (9.63 trillion cubic feet (Tcf)). Carbon dioxide (CO2) comprises about 14 mole % of the raw gas resource.The Gorgon joint venture is committed to the responsible management of greenhouse gas emissions and this ongoing commitment is reflected in the plan to inject Gorgon CO2 into the Dupuy Formation beneath Barrow Island, unless it is cost prohibitive or technically unfeasible.This paper summarises the Phase 1 assessment made by the Western Australian Department of Industry and Resources (DoIR) into the technical feasibility of the Gorgon CO2 storage project. Technical feasibility is defined as the ability to inject CO2 in a manner that has acceptable safety, environmental and reservoir risks based on assessments made by both the Gorgon joint venture and regulatory bodies.DoIR and ChevronTexaco Australia agreed to regularly review the technical work for due diligence purposes. To assist in the assessment, DoIR engaged the services of Curtin University. The Phase 1 review was completed in June 2003 and provided technical assurance on the feasibility of CO2 storage beneath Barrow Island. This provided one of the criteria for the WA State Government’s decision to grant in-principle access to Barrow Island for the project.The Phase 1 review provided a comparative risk analysis and recommendations related to improving the sub-surface definition of the earth model, further assessment of seal and fault integrity, injectivity, near-well bore reactions and CO2 surveillance and monitoring technologies. Key DoIR recommendations included the need for additional geological data and a long-term monitoring strategy for reservoir management and contingency planning. The second Phase of due diligence commenced in February 2004.
AUSTRALIA’S HYDROCARBON PROVINCES—WHERE WILL FUTURE PRODUCTION COME FROM?
Authors: Powell T.G.
Published: August 2017

The cumulative graph of reserves added to a basin through time is a measure of that basins’ exploration maturity. Additions of reserves through new field discovery are limited in the Bowen-Surat, Gippsland, Cooper-Eromanga and Bonaparte Basins whilst significant discoveries continue to be made in the Carnarvon Basin. The recent discoveries in the Perth Basin represent a significant new phase in the addition to reserves for this basin. Reserves growth in existing fields represents a very significant source of new crude oil reserves. All gas bearing basins including those in eastern Australia show potential for additional gas discoveries. Coal Bed Methane also represents a significant gas resource into the future.Australia’s production of crude oil has averaged 11% of the remaining reserves over the last decade. In the late 90s, the rate of production has exceeded the rate of addition to reserves and production must decline in the medium term. Medium- to long-term forecasts of future crude oil production are uncertain because of the difficulty in predicting the rate of crude oil discovery, particularly since many of the established plays in established crude oil basins appear to have little remaining potential and success rates and potential for new plays in established and frontier areas of exploration is unknown.Rates of gas production are not related to existing reserves, but rather to the dynamics of the commercial market which is strongly influenced by regional infrastructure.
THE NEGOTIATED PRICE OF CERTAINTY—RECENT DEVELOPMENTS IN NATIVE TITLE AGREEMENTS AFFECTING THE PETROLEUM INDUSTRY
Authors: Vickery E.J.
Published: August 2017

Development of Native Title agreements for Petroleum continues in parallel with the release of Court decisions on the law of Native Title. Negotiated agreements for three bidding rounds in the South Australian region of the Cooper Basin are now concluded, with exploration underway there and some new commercial production.These agreements were negotiated under the Commonwealth Native Title Act’s ‘Right to Negotiate’. Agreed resolutions are virtually demanded by the competing tensions within the legislative machinery. The need for conjunctivity of title from the exploration to the development stages is now understood and has become accepted by advocates for Native Title claimants. Recent court decisions would appear to ease the path for applications to the National Native Title Tribunal where negotiations fail to reach agreement, expanding the range of strategies open to Petroleum explorers seeking new title grants.Small negotiating teams facilitated progress. Despite a long first negotiation, subsequent negotiations have developed from that experience to form an efficient and cost-effective model which has now been replicated for more than 35 agreements conjunctive for all phases of activity. All those agreements address the key issues of title grants, both initially and consequently upon discoveries, Aboriginal heritage inspections and accommodation, including practical aides of indicative timelines and budgets for the latter, and compensation. Adaptation of these agreements is beginning in other parts of Australia. The temptation of Native Title advocates to test the envelope, however, must be expected with each new negotiation. Contrastingly, both the industry and state government agencies are seeking stabilisation of the terms of negotiated agreements to see how they will work in practice.This paper describes the key terms and temptations encountered so far in this evolving dynamic.
SUSTAINABILITY: A NEW ERA IN APPROVALS PROCESSES
Authors: Wylynko B. , Hartley A.
Published: August 2017

With its in-principle approval of the Gorgon gas proposal, the Western Australian government has heralded a new era —the era of sustainability assessments.No longer confined to strict environmental criteria, sustainability assessments will also consider the economic and social aspects of proposed oil and gas developments. This has a number of ramifications for the legal framework within which existing approvals processes operate.This paper examines traditional environmental assessment as represented by the processes used by Western Australia and the Commonwealth (which will be applied to the Gorgon proposal). It finds that while economic and social factors are expressly included in the legal framework, these factors have not played a large role in either assessing the significance of proposal impacts or in determining the conditions to be placed on the proposals. In the case of Western Australia, in 1996 the Supreme Court overturned recommendations by the Environmental Protection Authority, and a subsequent decision by the Minister for the Environment, on the basis that they had considered extraneous economic factors.Soon after approving the Gorgon proposal, the Western Australian Government published a State Sustainability Strategy. The strategy calls for sustainability assessments to be built upon existing environmental assessment processes. Having outlined the traditional environmental assessment process, the paper draws out a series of principles that may serve as a starting point for discussion about how to create sustainability assessment processes from environmental assessment processes. Key principles include comprehensiveness and an articulation of the objectives to be met through the assessments.The notion of sustainability is gradually becoming incorporated into the environmental legal framework. Sustainability assessments may be the next step in the development of that framework.
LEGAL FRAMEWORK AND LIABILITY OF LEAVING OIL AND GAS FACILITIES IN-SITU OR DEEP SEA DISPOSAL ON AUSTRALIA’S CONTINENTAL SHELF
Authors: Stejskal I.V.
Published: August 2017

Australia’s offshore petroleum industry is beginning to mature and many of its offshore oil and gas production facilities are reaching the end of their operational life. These facilities consist of an array of infrastructure including wells, wellheads, platforms and monopods of various construction, pipeline and flowlines, and anchors and risers. Many of these facilities will need to be decommissioned at the end of their operational and economic life in a safe and environmentally responsible manner.The Australian government has the jurisdiction to direct a company to remove all facilities associated with offshore production projects located on Australia’s continental shelf, but there is room for discretion for other decommissioning options. The manner in which facilities are decommissioned must be assessed on a case-by-case basis, taking into account factors such as technical feasibility, commercial risk, safety and social impacts, costs and environmental effects.Two decommissioning options appropriate in some instances are to leave selected facilities in-situ or dispose of a facility to some other location on the continental shelf, preferably in deep water. Residual liability refers to the responsibility and liability associated with leaving facilities on the seabed. If a facility is allowed to remain on the seabed, questions related to residual liability arise:who is responsible for any facility left on the seabed; andwho is liable to pay for compensation in the event that this facility is allowed to remain in place on the seabed and injury or damage is caused to a third person or property?There is no universally accepted practice in relation to residual liability in relation to decommissioning. In some countries, the State assumes responsibility; in other countries the company remains responsible in perpetuity. This issue still needs to be clarified in Australia.
ENGAGING THE EDUCATION COMMUNITY THROUGH PETROLEUM INDUSTRY SPONSORED PROGRAMS
Authors: Battrick M.A. , Bishop B.R. , Edmondson G.A.
Published: August 2017

The Schools Information Program (SIP), a joint venture of the Petroleum Club of Western Australia and APPEA, has operated as a successful model of the petroleum industry engaging with the Western Australian education community since 1991.Targetted at Year 10 students (15-year-olds) in mainly metropolitan Perth Government and private high schools, the SIP involves the delivery of a short-term (about six weeks) education program—in six parts. The program, together with its course materials and student assessment instruments, is designed to integrate with components of WA’s curriculum for Science, Social Science, Technology and Enterprise, and English. Operating in 22 Perth schools, the SIP framework is structured according to six core areas of the hydrocarbon industry sector:exploration;drilling;production;transportation;refining; andsustainable development.The program’s mode of delivery is largely via a series of classroom presentations by volunteer professionals drawn from the WA petroleum industry, together with field trips to relevant sites near Perth. The SIP is managed by a part-time co-ordinator (0.6) and the entire program is overseen by a ‘steering committee’, drawn from APPEA, the Board of Governors of the Petroleum Club of WA, along with some of the industry presenters.Individual companies in the industry are involved at a number of levels: co-ordinating presenters; preparing presentation materials; providing on-going support for students during the program; providing prizes as an incentive to the students; and also providing cash donations to assist with the costs of the Co-ordinator. The course materials consist of standard slide presentations (available in both electronic or OHP format), and are complemented by written worksheets, and a website integrated with the Petroleum Club of WA’s site. During the program, the students, working in groups, compete for substantial industry-related prizes, by completing a research project related to the SIP course content. A separate Board of Review assesses projects formally according to a set of established criteria.That the SIP is a success is confirmed quantitatively using formal ongoing program evaluation by the students, their teachers, and the industry presenters, and is evidenced by the number of schools seeking the limited places in the program. Other education initiatives (e.g. Speaking of Oil and Gas, and The Introduction to the Petroleum Industry seminars) are also discussed in this paper as they have links to the SIP.
TAXATION OF THE AUSTRALIAN OFFSHORE INDUSTRY: A PERSPECTIVE
Authors: Murray J.H. , Young D.W.
Published: August 2017

There is an extensive list of taxes (direct and indirect) that potentially apply to companies that explore and produce oil, gas or other hydrocarbons in Australia’s offshore waters. These taxes can include income tax, petroleum resource rent tax, royalties, goods and services tax, customs duties and fringe benefits tax. However, are such companies that produce in Australia taxed more than their counterparts in offshore locations elsewhere around the globe? This paper provides an insight into the principal forms of direct taxation that apply to the Australian offshore production industry. It examines the nature of the taxes applied, the rate of taxation and how the tax take has moved over the years since the first offshore exploration permits were granted in Australia in the late 1950s. The paper gives examples of how in practice each of the relevant taxes would apply throughout the life of a field and compares the taxation burden in Australia to that in other key offshore producing jurisdictions such as the UK, US and Norway. The paper concludes by looking at some of the economic and political factors that must be addressed by the Australian Government if Australia is to maintain a fiscally balanced tax regime to encourage further investment in our offshore industry.
2003 EXPLORATION HIGHLIGHTS
Authors: Willink R.J.
Published: August 2017

The exploration and appraisal highlights of 2003 are reviewed through the granting of selected exploration awards to companies who made significant discoveries during the year, successfully appraised existing fields, invested heavily in frontier exploration, or otherwise applied leading edge technology to advance the exploration cause.
PESA INDUSTRY REVIEW 2003
Authors: Hann J.
Published: August 2017

Five developments started production in 2003—these were ARC Energy’s HOVEA onshore oil development Perth Basin, OMV’s Patricia Baleen offshore/onshore gas development in East Gippsland, ENI’s Woollybutt and Apache’s Double Island offshore oil fields and Woodside completed the first phase of their NW Shelf expansion project (Fig. 1).
TOWARDS DEVELOPMENT OF AUSTRALIA’S LARGE DEEPWATER GAS FIELDS
Authors: Ronalds B.F.
Published: August 2017

Australia can anticipate a more extensive gas production future than any other OECD country. At the same time, much of our gas resource is located in large, remote, deepwater reservoirs. There is very little experience in bringing such fields to market, although several current developments internationally indicate that a new era of deepwater gas production is beginning. The limited knowledge base suggests that Australia could, and indeed should, take a lead in developing strategies and technologies necessary to produce major deepwater gas and gascondensate fields in an economically, environmentally and socially sustainable manner in the long-term.This paper draws on a comprehensive database of deepwater field developments around the world to identify specific capability gaps, and the technology breakthroughs that may enable them to be overcome. Emphasis is placed on both floating facilities and all-subsea production solutions, with ultra-long tiebacks and floating LNG bringing particular benefits in the Australian context. Compact GTL is a key enabling technology for remote deepwater fields with associated gas.
DEEPWATER GAS FIELD PRODUCTION FROM SUBSEA WELLS INTO COMPRESSED NATURAL GAS CARRIERS THROUGH A HYBRID RISER TOWER
Authors: Saint-Marcoux J-F. , White C. , Hovde G.O.
Published: August 2017

This paper addresses the feasibility of developing an ultra-deepwater gas field by producing directly from subsea wells into Compressed Natural Gas (CNG) Carrier ships. Production interruptions will be avoided as two Gas Production Storage Shuttle (GPSS) vessels storing CNG switch out roles between producing/storing via one of two Submerged Turret Production (STP) buoys and transport CNG to a remote offloading buoy. This paper considers the challenges associated with a CNG solution for an ultra-deepwater field development and the specific issues related to the risers. A Hybrid Riser Tower (HRT) concept design incorporating the lessons learned from the Girassol experience allows minimisation of the vertical load on the STP buoys. The production switchover system from one GPSS to the other is located at the top of the HRT. High-pressure flexible flowlines with buoyancy connect the flow path at the top of HRT to both STP buoys. System fabrication and installation issues, as well as specific met ocean conditions of the GOM, such as eddy currents, have been addressed. The HRT concept can be also used for tiebacks to floating LNG plants.
A QUICK-LOOK EVALUATION OF THE SANDING POTENTIAL OF PRODUCTION WELLS IN THE YOLLA FIELD
Authors: Pallikathekathil Z.J. , Marsden J.R. , Suttill R.J. , Mussared M. , Qiuguo L.
Published: August 2017

The preliminary downhole completions and surface facilities for the Yolla field had been designed based on the well test results from the Yolla–1 well. This well had produced insignificant sand during production testing, but during the field development planning, there was a concern raised regarding the propensity of some zones to sand. If the zones were prone to sanding, then the design of completions and surface facilities would have to be re-worked on with steps taken to mitigate any sanding. Mitigation steps would include perforation strategy (selective zone perforation, oriented perforation), sand screen or gravel pack.Therefore, a quick-look evaluation of the sanding potential of the particular zones of interest was undertaken to be completed within the project time frame. The sand zones analysed were Sand–2718, –2755, –2809, and –2973 from the Eastern View Coal Measures(EVCM).Yolla–2 well had the most complete data set available. A mechanical earth model (MEM) containing information on rock properties, pressures and in-situ stresses was constructed based on open-hole log data from the Yolla–2 appraisal well. Laboratory tests provided some uni-axial compressive strength (UCS) data for calibration of the model. The MEM data were input into sanding analyses, for various reservoir depths and for selected completion and perforation options. Since some MEM parameters were poorly constrained, best- and worst-case scenarios and sensitivities were evaluated to assess the influence of geomechanical parameters on sanding propensity.When Yolla–3 and –4 were drilled, more complete sets of logs were acquired and used to improve confidence in the earlier evaluations, and to check the validity of certain assumptions that had been made. With revised evaluation for Yolla–3 and –4, decisions on the completion strategy and perforation intervals were taken and implemented in the field development planAfter completion, both Yolla–3 and Yolla–4 were tested and sanding rates were monitored. After initial transient production of sand during clean-up, sand rates produced were insignificant. This confirmed the results of the quicklook geomechanical analyses that had been conducted.
AUSTRALIA—SOVEREIGN RISK AND THE PETROLEUM INDUSTRY
Authors: Young D. , Brockett R. , Smart J.
Published: August 2017

Australia has rejoiced in its reputation for having low sovereign risk and corresponding rating, for decades. This reputation was bruised in the first decade after the High Court introduced Native Title into Australian law by the legislative response of the then Government, but has since recovered, and enjoys the world’s lowest country risk rating, and shares the worlds best sovereign risk rating with the USA. A number of government precipitated occurrences in recent times, however, raise the question: for how long can this continue?This paper tracks the long history of occasional broken resource commitments—for both petroleum and mining interests—by governments at both State and Federal level, and the policies which have driven these breaches. It also discusses the notorious recent cancellation of a resource lease by the Queensland Government, first by purporting to cancel the bauxite lease and, after legal action had commenced, by a special Act of Parliament to repeal a State Agreement Act. This has raised concerns in boardrooms around the world of the security of assets held in Australia on a retention, or care and maintenance basis.The paper also looks at the cancellation of the offshore prospecting rights held by WMC, with no compensation. This was a result of the concept that rights extinguished by the Commonwealth, with no gain to the Commonwealth or any other party do not constitute an acquisition of property, thereby denying access to the constitutional guarantee of ’just terms’ supposedly enshrined in the Australian Constitution where an acquisition has occurred.Some other examples are the prohibition on exploration in Queensland national parks last November. This cost some companies with existing tenures a lot of money as exploration permits were granted, but then permission to do seismic exploration refused (Victoria). Several losses of rights occurred as a result of the new Queensland Petroleum and Other Acts Amendment Act after investments have been made.Changes in fiscal policy can also impact on project viability, and some instances of this are considered.This paper also explores ways these risks can be minimised, and how and when compensation might be recovered.
RISK APPETITE: A HUNGER FOR THE UNKNOWN OR STRANGLEHOLD ON GROWTH?
Authors: Johnson B.K.
Published: August 2017

The recent extreme volatility in the petroleum markets has introduced a level of volatile earnings for exploration and production companies (E&P) that has not been seen since the Gulf war in 1990–91. Many companies have reduced their hedging activity to increase exposure to rising oil prices and have consequently benefitted considerably. Rapid increases in oil prices historically have been followed by just as rapid decreases. Although oil prices are a key value driver for E&P companies so is exploration and development success, production variability, operational management, and, for companies who do not report in $US, foreign exchange rates. All these value drivers contribute to top line revenues and earnings so hedging oil price in isolation from other value drivers can have adverse financial consequences. The quarterly focus by investors of listed companies on meeting earnings targets/guidance creates the pressure for the board of directors of E&P companies to focus on the degree of earnings stability that is acceptable to the market. This is reflected by a company’s aversion to risk, or risk appetite. The collective management of the value drivers as a portfolio of risks allows companies to understand the potential for earnings variance, or earnings at risk during reporting periods. This, in turn, can provide companies with a degree of confidence in meeting earnings targets and the opportunity for companies to increase their transparency in terms of disclosure/communication of how effectively it is managing core value drivers of the business.
IS THERE A FUTURE FOR STATE AGREEMENTS?
Authors: Castledine A.G. , Lamattina M.
Published: August 2017

State Agreements are agreements between private proponents and a State government which aim to facilitate the development of resources and processing projects and associated public infrastructure. State Agreements have been used extensively throughout Australia and each has been given varying levels of legislative recognition and effect, which in turn affects whether the rights and obligations arising under them have statutory or merely contractual effect. This ambiguity highlights the need to balance within State Agreements the private rights of the proponents with the public interest. The public interest critically involves third party rights to access infrastructure or services developed by proponents under the State Agreement. The introduction of National Competition Principles and regulatory regimes has affected the balance of these interests in favour of the public interest which has, in turn, led to a more stringent approach to State regulation under State Agreements. In particular, States are compelled through inter-governmental, federal and international competition and trade agreements to limit the extent to which it can negotiate its terms in a purely commercial way, embodying concessions in favour of proponents or preferences in favour of the State over other states or countries. Where a State Agreement expressly confers a benefit on third parties associated with access, third parties have successfully sought to enforce those benefits through the Courts, resulting in increased risks and costs for proponents that may not have been originally anticipated. Coupled with the political risks associated with changing governments and government policies, State Agreements, which have historically played a significant role in State development, are increasingly losing their ability to meet the commercial objectives of proponents.
STABLE HYDROGEN ISOTOPE RATIOS OF SEDIMENTARY HYDROCARBONS: A POTENTIAL METHOD FOR ASSESSING THERMAL MATURITY?
Authors: Dawson D. , Grice K. , Alexander R.
Published: August 2017

A relationship has been identified between the maturity level of source rocks and the stable hydrogen isotopic compositions (δD) of extracted saturated hydrocarbons, based on the analysis of nine sediments and five crude oils from the Perth Basin (WA). The sediments cover the immature to late mature range. Distinct δD signatures are observed for the immature sediments where pristane and phytane are significantly depleted in deuterium (D) relative to the n-alkanes. With increasing maturity the difference between the δD values of n-alkanes and isoprenoids reduces as pristane and phytane become progressively enriched in D. The n-alkane–isoprenoid δD signature of the crude oils, including one from a different source facies, is similar to mature–late mature sediments representative of the peak oil–generative window. Enrichment of D in isoprenoids is attributed to isotopic exchange associated with thermal maturation. Average δD values of pristane and phytane correlate well with vitrinite reflectance, as does the biomarker maturity parameter Ts/Tm. The limited data set suggests that δD values of aliphatic hydrocarbons may be useful for establishing thermal maturity, particularly when other maturity parameters are not appropriate. Furthermore, we suggest δD values may be useful over a wider maturity range than traditional parameters, particularly at very high maturity where biomarker parameters are no longer effective.
SEISMIC EVIDENCE FOR REVERSE AND WRENCH FAULT TECTONICS—CLIFF HEAD OIL FIELD, PERTH BASIN
Authors: Hodge C.C.
Published: August 2017

Seismic interpretation of the Cliff Head oil field has shown it to be structurally complex with reverse faults, wrench faults and listric faults mapped at both field and reservoir scale within the Permo-Triassic section.The Cliff Head field overlies the Abrolhos Transfer Zone and has strong similarity to the progressive evolution, internal structure and rhomboid map geometry in experimental models of restraining stepovers in strikeslip systems. It is concluded that the Cliff Head oil field is a pop-up structure formed during the Permian and early Cretaceous within a restrained convergent wrench system—the result of sinistral transpression.A similar style of faulting could be applied when mapping seismic data in other offshore areas and especially the onshore Perth Basin with its poorer seismic data quality.Interpretation of prospects with a strong reverse or wrench component has implications for the timing of hydrocarbon emplacement and the potential for seal breach and leakage. Furthermore, paleo-structural style will determine fracture density and orientation and may be critical in determining optimum design of producer and injection wells during field development.It is recommended that interpreters of seismic data in the Perth Basin treat the fault patterns and structural trends of the Permian and early Cretaceous as different structural packages. The two should only be linked when it is very clear that there is a strong early Cretaceous overprint.
MULTIPLE REMOVAL SUCCESS IN THE CARNARVON BASIN WITH SRME
Authors: Long A. , Zhao P. , Gatley P. , Cooke D. , Borselen R. van , Schonewille M. , Hegge R.
Published: August 2017

In 2003, Santos Ltd revisited a poor data quality area in the northern Carnarvon Basin, offshore Western Australia, where both short and long period multiple energy prohibits imaging of the underlying geology. Previous reprocessing efforts had failed to satisfactorily improve data quality, or reduce the level of multiple contamination. A two-dimensional (2D) reprocessing project was initiated to establish whether any modern variant of Surface-Related Multiple Elimination (SRME) could have success. Consequently, several versions of SRME were tested, with all output diagnostics being imaged with anisotropic Kirchhoff pre-stack time migration (PSTM). The new SRME results are a significant improvement over previous reprocessing efforts, and provide a much better platform for the picking of anisotropic velocity functions, and the application of PSTM imaging. Most of the multiple energy in this location is actually surface-related, with only a small component of internal multiple reverberations. Both long and short period multiple energy was successfully removed, and interpretation can now be pursued with more confidence in a difficult data location. Many outof- the-plane events still appear to contaminate the final 2D result, so a full three-dimensional (3D) production project was then pursued using standard (2D) SRME processing applied to 3D data gathers.Despite many noise challenges existing within the 3D field data, the final data images shed new light on a challenging geological environment, and prove the merits of SRME processing. A new generation of 3D acquisition and processing technology is now required to improve upon existing results, so a brief consideration is also given to the potential applications of 3D SRME processing to 3D seismic data from the North West Shelf. A brief example from offshore Brazil is used to illustrate the potential benefits of 3D SRME.
3D PRE-STACK DEPTH MIGRATION: A TOOL FOR REDUCING EXPLORATION RISK IN THE SWAN GRABEN, TIMOR SEA
Authors: Bocca P. , Fava L. , Stolf E.
Published: August 2017

3D pre-stack depth migration (PSDM) reprocessing was conducted in 2003 on a portion of the Onnia 3D seismic cube, located in exploration permit AC/P-21, Timor Sea.The main objective of the reprocessing was to obtain the best seismic depth image and the most realistic structural reconstruction of the sub-surface to mitigate the risk factors associated with trap definition (trap retention and trap efficiency). This represents one of the main challenges for oil exploration in the area.The 3D PSDM methodology was chosen as the most appropriate imaging tool to define the correct sub-surface geometry and fault imaging through the use of an appropriate velocity field. An integrated approach to building the final velocity model was adopted, with a substantial contribution from the regional geological model.Several examples are given to demonstrate that the 3D PSDM reprocessing significantly improved the seismic image and thus the confidence in the interpretation, contributing strongly to the definition of the exploration targets.The interpretation of the new seismic data has resulted in a new structural picture in which higher confidence in seismic imaging has improved fault correlation. This has enabled better structural definition at the Middle Jurassic Plover Formation level that has reduced the complexity of the large Vesta Prospect, in the centre of the Swan Graben to the northwest of East Swan–1. Improved understanding of the fault reactivation mechanism and the structural elements of the trap (trap integrity) were eventually incorporated in the prospect risking.In the Swan Graben 3D PSDM has proved to be a very powerful instrument capable of producing significant impact on the exploration even in an area with a complex geological setting and a fairly poor seismic data quality.
ANALOG RESERVOIR MODELLING OF CHANNEL SANDS
Authors: Sherlock D. , Weir G. , Dodds K.
Published: August 2017

This paper outlines the results of analog modelling of a sandy deepwater channel reservoir to gain insight into issues of uncertainty in reservoir simulations and their seismic expression. The project is unique in that it integrates seismic and reservoir engineering research in a controlled laboratory environment. Unlike numerical modelling investigations, this laboratory-based modelling study provides real data that does not rely on assumptions and is, therefore, a useful case study for comparing the actual production and seismic response against numerical predictions.The 1 m2 model comprised two intersecting synthetic sandstone channels within a transparent acrylic matrix. The model was initially oil-saturated with irreducible water and was produced through waterflooding of the upper channel. Careful attention was paid to scaling of both the fluid dynamics and the seismic properties to ensure that the response of the model was representative of the field-scale environment. Scaled time-lapse seismic data was recorded before and after production and data such as water cuts, recovery rates and pressure drop between injector and producers were also recorded.Analog reservoir modelling (ARM) provides a new tool that allows seismic attributes to be evaluated against ground truth results and the performance of seismic inversion schemes to be critically assessed.
DOES SELF-REGULATION IMPROVE CORPORATE ECOLOGICAL-EFFICIENCY? AN EMPIRICAL INVESTIGATION INTO THE AUSTRALIAN PETROLEUM INDUSTRY FROM 1996 TO 2002
Authors: Sarker T.K. , Burritt R.L.
Published: August 2017

This study presents a detailed description of greenhouse gas emissions and reduction strategies adopted by the Australian petroleum industry from 1996–2002. An empirical analysis has been undertaken to examine the impact of such strategies in improving overall industry environmental performance and has ranked them to establish their relative importance in improving corporate ecological-efficiency ratios, a relative measure of environmental performance that compares the production of oil and gas and their environmental impact added. Two major classes of environmental self-regulatory activities identified are greenhouse gas management strategies and greenhouse gas influence strategies; where the latter was found highly inconsistent throughout the study period. We found that investment in emissions abatement activities, environmental collaboration and staff training, implementation of greenhouse policies and environmental reporting act as better greenhouse gas management strategies. In contrast, changing consumer behaviour or demand side management and supporting research and development on projects that reduce greenhouse gas emissions act as better influence strategies. We predict that the two classes of environmental strategies are highly inter-linked and that an optimal combination is needed for achieving better corporate environmental performance. The study provides a basis for the improvement in greenhouse gas management that may help in attaining an effective emission management plan for the industry.
A STATE-OF-THE-ART SHORE CROSSING
Authors: Jas E.P. , McPhee A.T.
Published: August 2017

An insight is provided into the design and construction of the shore crossing of the export pipeline system for the Otway Gas Project in Western Victoria. The development of the Otway Gas Project, which is now underway, requires the installation of a 20-inch gas pipeline and a 4-inch glycol service line across the shoreline in the Port Campbell National Park along the Great Ocean Road, one of the major tourist attractions in Australia. An account is given of the landfall site selection process, the collection of required site data, the identification of geo-hazards, the development of a unique construction method based on a combination of retractable micro-tunnelling and horizontal directional drilling, and an outline of the construction challenges. These include the complex geo-technical conditions, the ever present high-energy Southern Ocean swell, and the environmental significance of the site. The design and construction work performed demonstrates that trenchless technology can successfully be applied for the installation of pipelines across shorelines provided detailed attention is paid to a number of design and construction aspects; bearing in mind that horizontal directional drilling design guidelines are generally limited with respect to these crossings.
4D PLANNING AND EXECUTION STRATEGIES FOR AUSTRALIAN RESERVOIR MONITORING PROJECTS
Authors: Long A.S. , Widmaier M. , Schonewille M.A.
Published: August 2017

Time-lapse (4D) reservoir monitoring is in its infancy in Australia, but is on the verge of becoming a mainstream pursuit. We describe the 4D seismic acquisition and processing strategies that have been developed and proven elsewhere in the world, and customise those strategies for Australasian applications.We demonstrate how a multidisciplinary pursuit of real-time acquisition and processing Quality Control (QC) is an integral component of any 4D project. The acquisition and processing geophysicists must be able to understand all the factors contributing to the 4D seismic signal as they happen. Such an understanding can only arise through rigorous project QC and management using interactive visualisation technology. In turn, the production geologists and reservoir engineers will then receive 4D seismic products that can be robustly and confidently used for the construction of accurate reservoir models and the pursuit of reliable reservoir simulations and forecasts.
LARGE-BORE GAS WELL DESIGN—APPLICATION TO OFFSHORE GAS FIELD DEVELOPMENT
Authors: Thompson F. , Terziev I. , Taggart I.
Published: August 2017

Offshore gas development projects including the North West Shelf of Australia continue to develop new technologies in order to reduce development costs. Given that the number of development wells directly relates to capital expenditure, past attempts have focussed on obtaining higher gas rates out of conventional well designs by carefully managing erosional limits, which, in turn, tend to restrict the use of higher offtake rates.A strategy based on safely flowing gas wells at higher rates results in fewer wells and delays the phasing-in of additional wells, both of which result in economic enhancement. In recent times the industry has increasingly moved to large-bore gas well technology as a means of realising this strategy. Large-bore gas wells are defined as wells equipped with production tubing and flow control devices larger than 7” or 177 mm. Originally developed for land-based operations, this technology is increasingly moving offshore into totally subsea systems. One factor limiting the speed of adoption of this technology is the trade-off that exists between the increased offtake rates offered by large-bore systems and the risks posed by wear due to erosion in and around the wellhead area caused by any solids entrained in the gas stream.The problem becomes more acute when different-sized well designs employ the same wellhead configurations, because the upper wellhead area is usually the critical and limiting wear component.This paper summarises the recent developments in large-bore offshore applications and presents a consistent methodology showing how different gas well designs can be compared using hydraulic and erosional considerations. Additional trade-offs posed by reliable solids monitoring and the adoption of untested wellhead and intervention designs are discussed. In many cases, hybrid designs based on large diameter tubulars but with conventional wellheads may offer a useful balance between higher well rates and adoption of proven technology. The results shown here are directly applicable to alternative well designs presently under consideration for a number of offshore reservoir developments.
FORMATION EVALUATION AND STATIC MODELLING IN THE WHEATSTONE GAS FIELD
Authors: Theologou P. , Whelan M.
Published: August 2017

The Wheatstone gas discovery is located about 110 km north-northwest of Barrow Island in the Dampier Subbasin, northwest Australia. Gas was intersected within the AA sands of the Mungaroo Formation, and within a thin overlying Tithonian sand. Core was acquired through the base of the Tithonian sand and the upper section of the Mungaroo Formation.A combination of logging while drilling, wireline logging, core acquisition and special core analysis has formed the basis of an extensive formation evaluation program for Wheatstone–1. The acquisition of this dataset, and associated interpretation, has allowed Chevron to maximise its ability to characterise the reservoir early in the field’s history, and thereby has helped our understanding of the uncertainties associated with the formation evaluation and geological modelling of this fluvial system. Petrological studies indicate that reservoir properties and mineralogy are strongly correlated with the mean grain size of the formation. The mineralogy of the sands is relatively simple with minor quartz overgrowth, K-feldspar dissolution and kaolinite precipitation being the dominant diagenetic events. The better quality sands are generally devoid of significant amounts of clays such as illite-smectite. Within the Tithonian sand, more exotic mineral suites are present including glauconitic and phosphatic minerals.A comparison of resistivity data from wireline and logging while drilling (LWD) across cored and non-cored intervals through the Mungaroo Formation has revealed the impact that slow coring has had on formation filtrate invasion. It has been interpreted that the combination of slow rate of penetration, non-optimised mud properties, and coring assembly design resulted in deep invasion through cored intervals. Deep resistivity response through the invaded formation was subdued, and initially resulted in an underestimation of reserves. The incorporation of saturation information from capillary pressure data has provided for a more realistic view of gas-in-place.In this early stage of field appraisal, the generation of representative and fit-for-purpose reservoir models is somewhat difficult due to the small amount of available data existing away from the well. To provide realistic information on the potential range of gas-in-place for the field, experimental design methodology was incorporated into the modelling work-flow. Experimental design allows for rapid and comprehensive modelling of the possible range of the dependant variables, in this case GIIP (gas initially in place). Assimilation of geological analogues, formation evaluation and their inherent uncertainties has attempted to capture the range of GIIP in this world-class gas discovery.
UNCONVENTIONAL BOREHOLE BREAKOUT ROTATION ANALYSIS PROVIDES A QC TOOL FOR STRESS MODELS
Authors: Camac B.A. , Hunt S.P. , Boult P.J. , Dillon M.
Published: August 2017

In distinct element (DEM) numerical stress modelling, the principal stress magnitudes and orientations are applied to the boundary of the 3D model. Due to data restrictions and typical depths of investigation, it is possible to have much uncertainty in the conventional methodologies used to constrain the regional principal stress magnitudes and orientations.A case study from the Kupe field in the Taranaki Basin, New Zealand is presented where the uncertainty in the input data made it difficult to determine which stress regime—a transitional normal/strike-slip or reverse/thrust—is active at reservoir depth (approximately 3,000 m). The magnitudes and orientation of the principal stresses were constrained using published techniques. A sensitivity analysis was applied to account for the uncertainty in the input data. A model of the Kupe field incorporating 18 major faults was subsequently loaded under both derived stressed regimes, using the calculated magnitudes.Borehole breakout analysis was used to acquire interpreted orientations of the maximum principal stress (Shmax). The work presented herein describes a different or unconventional approach to the general petroleum geomechanics methodology. Typically, the breakout data is averaged to get one data point per well location. Here, all breakout data is retained and displayed vertically. The data is actively used and the variations with depth can be seen to show how faults can generate local perturbations of the regional stress trajectory. These data are then used to compare the observed or field indications of the breakouts along the borehole with the modelled Shmax predicted by both end point DEM stress models. This comparison has provided additional confidence in the derived stress regime and the derived stress models for the Kupe field. The stress models are used to predict areas of enhanced hydrocarbon pooling and low seal integrity.
GEOSEQUESTRATION—A SOLUTION FOR AUSTRALIA?
Authors: Warburton A.M. , Grove J.A. , Then S.
Published: August 2017

Managing its growing greenhouse gas emissions has become a key issue in Australia’s energy and environmental policy.Geological storage (or geosequestration) of carbon dioxide emissions produced by power stations and gas processing plants is being promoted as an innovative way to combat the threat of climate change. Australian governments and industry are interested in the process because it would allow Australia to continue to rely on its extensive fossil fuel reserves as an energy source and export commodity into the future. The process, however, is still in an experimental phase. If geosequestration does prove to be a viable technology then regulatory changes will be required to facilitate large-scale commercial use.This paper discusses the status of geosequestration development in Australia. It considers some of the key legal and regulatory issues that would need to be addressed to allow geosequestration projects to proceed, including:jurisdictional issues between State and Commonwealth governments;access to land and rights to use storage sites;priorities between competing land uses;potential application of third party access regimes to geosequestration infrastructure;potential legal liabilities, especially over the longer term; and,the extent to which a consistent national approach to the regulation of geosequestration may be required. This paper is general in nature and must not be relied upon as legal advice in any respect.