Journal articles on the topic 'Petroleum Victoria'

There are three petroleum basins of differing character off the Victorian coast: the Otway, Bass and Gippsland basins. These formed during continental rifting between Australia, Antarctica and New Zealand, associated with the break up of Gondwana Marked variation in the development of these basins appears to have been largely controlled by the distribution of Proterozoic basement—the Selwyn Block—under central Victoria. Lying deep under central Victoria, this block surfaces towards the coast and continues southward as the Proterozoic crust of western Tasmania. The boundaries of this block are coincident with the boundaries separating the three basins. The Otway Basin in western Victoria represents a clean break between Australia and Antarctica. The Otway Basin has thick fill upon thinned continental crust with an outboard break to a continent-ocean boundary. The overall geometry here is a classic lower plate margin. This clean continental break-up failed to propagate eastward across the Proterozoic Selwyn Block. Instead, localised continental stretching resulted in some grabens and the overlying steers head sag of the Bass Basin. True continental separation was transferred southward to the margin of the Tasmania/Selwyn Block. The Gippsland Basin lies east of the Selwyn Block. Its development reflects initial southern margin rifting, but this was overtaken by orthogonal-oriented Tasman rifting. This left the Gippsland Basin with a complex interplay of north-south and east-west structures controlling the platforms, terraces and deeps.

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2012, 27 areas in nine offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or twelve months after the release date, i.e. 8 November 2012 or 9 May 2013, depending on the exploration status in these areas and on data availability. As was the case in 2011, this year’s Release again covers a total offshore area of about 200,000 km2. The Release Areas are located in Commonwealth waters offshore Northern Territory, Western Australia, South Australia, Victoria and Tasmania (Fig. 1). Areas on the North West Shelf feature prominently again and include under-explored shallow water areas in the Arafura and Money Shoal basins and rank frontier deep water areas in the outer Browse and Roebuck basins as well as on the outer Exmouth Plateau. Following the recent uptake of exploration permits in the Bight Basin (Ceduna and Duntroon sub-basins), Australia’s southern margin is well represented in the 2012 Acreage Release. Three new areas in the Ceduna Sub-basin, four areas in the Otway Basin, one large area in the Sorell Basin and two areas in the eastern Gippsland Basin are on offer. Multiple industry nominations for this Acreage Release were received, confirming the healthy status of exploration activity in Australia. The Australian government continues to support these activities by providing free access to a wealth of geological and geophysical data.

The Otway Basin is one of the best known and most actively explored of a series of Mesozoic basins formed along the southern coastline of Australia by the rifting of the Antarctic and Australian plates during the Cretaceous. The basin offers a diversity of play types, with at least three major sedimentary sequences forming conventional targets for petroleum exploration in the onshore basin. The Penola Trough in South Australia has enjoyed over 20 years of commercial hydrocarbon production from the sandstones of the Early Cretaceous Otway Group comprising the Crayfish Subgroup (Pretty Hill Formation and Katnook sandstones) and Eumeralla Formation (Windermere Sandstone Member). Lithostratigraphic characterisation and nomenclature for these sequences are poorly constrained, challenging correlation across the border into the potentially petroleum prospective Victorian Penola Trough region. The Geological Survey of Victoria (GSV), as part of the Victorian Gas Program, commissioned Chemostrat Australia to undertake an 11-well chemostratigraphic study of the Victorian Otway Basin. The South Australia Department for Energy and Mining, GSV and Chemostrat Australia are working collaboratively to develop a consistent, basin-wide schema for the stratigraphic nomenclature of the Otway Basin within a chemostratigraphic framework. Variability in the mineralogy and hence inorganic geochemistry of sediments reflects changes in provenance, lithic composition, facies changes, weathering and diagenesis. This geochemical variation enables the differentiation of apparently uniform sedimentary successions into unique sequences and packages, aiding in the resolution of complex structural relationships and facies changes. In this paper, we present the preliminary results of detailed geochemical analyses and interpretation of 15 wells from across the Otway Basin and the potential impacts on hydrocarbon prospectivity.

BHP Petroleum practice is to undertake a comprehensive environmental management program for exploration activities in environmentally sensitive areas. The planning for the exploration program in the Otway and Duntroon Basins is presented as a case study.BHP Petroleum's exploration activities in the Otway Basin, offshore Victoria, have been the subject of community debate as a result of the perceived effects on sensitive environmental values. The environmental management program undertaken for this exploration project included:a community consultation and information program;development of a geographic information system (GIS) recording a range of environmental and logistical (spill response) information;a whale research program; andformulation and implementation of an environmental management plan.This program and the issues it is designed to address has been an education for the Company, the community and government agencies.

Last year the petroleum industry witnessed the enactment of new legislation both at Commonwealth and State levels. The principal legislative change to environmental management was the introduction of the Commonwealth Government’s Environmental Protection and Biodiversity Act, 2000 (EPBC Act). South Australia and Victoria also implemented new Petroleum Acts and/ or Regulations.Construction of the Eastern Gas Pipeline was also completed last year, whilst preliminary approvals and environmental assessment continues for the Papua New Guinea, Timor Sea and Tasmania Natural Gas pipelines. Offshore exploration continued, particularly in the North West Shelf, Otway Basin, Timor Sea and Bass Strait.Other critical areas of environmental management included greenhouse gases, national pollution inventory reporting and the increasing requirements for environmental approval and management under various state environmental legislation.This paper provides an overview of environmental developments in the petroleum industry during the year 2000, in particular, the implication of new legislation, new technology, e-commerce and a greater focus on environmental reporting.

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

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.

Unitisation is a commercial agreement between the titleholders of a shared petroleum pool that extends across two (or more) title boundaries.In 1998, a working group involving government and industry representatives was formed, with the intent of drafting a guideline on unitisation. However, work on the guideline was put on hold until after resolution of the Perseus Athena unitisation issue. During the intervening period, a number of new unitisation cases have arisen and a further number are on the horizon.A workshop was held in Perth on 22 February 2001 to canvass opinions and options on unitisation. Around 30 representatives from government (Commonwealth, Western Australia, Victoria, Northern Territory and the Timor Gap Joint Authority) and industry (APPEA, Agip, Apache, BHP, ExxonMobil, MIMI, Phillips, Santos, Shell and Woodside) attended and contributed to the Workshop.There is general agreement among industry and government representatives that there is a range of unitisation issues under the Petroleum (Submerged Lands) Act 1967 (PSLA) that need to be clarified. In response, the Commonwealth is examining those parts of the Act that deal with property rights with respect to shared pools and when government should direct unitisation. This could lead to changes to the PSLA depending on consultations with interested parties on these matters.The aim of this paper is to canvas a number of options with regards to property rights and government direction. These options could also help resolve a range of other issues relating to unitisation, including information sharing and secondary taxation of unitised fields.

Bill’s presentation is on behalf of the NT, Queensland, NSW, Victoria, SA and WA. Some highlights are: • NT: 24 onshore exploration applications were received in 2010 (an increase of 50 % from 2009). About 479,100 sq km of the NT is now under application, including grassroots areas. • Queensland: In 2011, a variety of exploration opportunities are being offered in basins ranging in age from Precambrian to Cretaceous. Targets include conventional oil and gas as well as shale gas. • NSW: There are now more than 800 unallocated petroleum exploration blocks, including the Darling Basin, the Tamworth Moratorium area, and the Oaklands Basin Moratorium area. • Victoria: Acreage release is proposed for the onshore Otway Basin in 2011. • SA: The CO2010 acreage release, comprising three blocks in the Cooper and Eromanga basins, closed on 10 March 2011. • WA: To coincide with the APPEA Conference, acreage has been made available for bidding from the Canning Basin, Northern Carnarvon Basin, Officer Basin and Perth Basin.

On behalf of itself and BHP-B, Esso operates offshore production platforms in Bass Strait, a crude stabilisation and gas processing plant at Longford and a LPG fractionation plant at Long Island Point, Victoria. The Technical Surveillance Program for these facilities is implemented at both the Operator and Engineering levels. The program has been enhanced by building on existing DCS process control and process information (PI) systems and through development of a more structured engineering monitoring system. The enhanced program continues to register tangible benefits in integrity, product quality, recovery, efficiency and reliability and capacity.At the operator level, the process is monitored continuously, assisted by process alarms to maintain the plant within the normal desirable operating zone. Safe operating limits define the outside boundary of the safe operating envelope which is secured with shutdown and other automatic protective devices. Alarm and limit conditions associated with these parameters have been incorporated into the DCS control system with pre-defined operator responses appearing automatically on the screen if the condition is reached.At the engineering level, the surveillance program is a systematic periodic monitoring process focussing on optimum performance and continuous improvement. It is structured using the elements of a management system. Within this framework, engineering spreadsheets have been developed with direct links to process data via process information system software. The spreadsheets assist plant engineers to efficiently monitor the key performance variables; they also pre-define the acceptable operating range, calculate statistical performance, highlight deviations and hyperlink back to the PI system for more detailed troubleshooting. Day-today deviations and performance improvements are fed back and reviewed at the working level, more significant issues are formally investigated and reviewed with management. Key data and overall performance is summarised monthly, and formally reviewed by plant and engineering management.

The Australian Government’s 2018 offshore petroleum exploration acreage release was announced by the Commonwealth Minister for Resources and Northern Australia, Senator the Hon Matthew Canavan at the 2018 APPEA conference. This paper provides insights into the processes that the Australian Government has undertaken to select the final release areas and goes into detail on the ongoing petroleum related activities of the Department of Industry, Innovation and Science (the Department). The annual acreage release is a central component of ensuring ongoing, sustainable and responsible investment in Australia’s offshore petroleum sector. The annual acreage release remains the primary mechanism for securing investment in offshore oil and gas exploration in areas of known petroleum potential and new geological frontiers. Continued exploration for oil and gas in Commonwealth waters is a central component of ensuring Australia’s future energy security. Australia’s well established and independent environmental regulator, NOPSEMA (the National Offshore Petroleum Safety and Environmental Management Authority), ensures all petroleum activities in Commonwealth waters are performed safely and in an environmentally responsible manner. Combined with NOPTA’s (National Offshore Petroleum Titles Administrator) leading practice titles administration, Australia remains an attractive investment destination while offering industry leading environmental protections and ensuring safe working conditions industry-wide. Australia offers investors access to data, secure tenure, a stable economic environment and a well-established transparent regulatory system for offshore petroleum activities. A key driver for sustainable activity in Australia is the acceptance of multiple use access to Australia’s marine resources. Recognising this, the department consults with a range of stakeholders on the areas it proposes to release for petroleum exploration. This consultation process provides an opportunity for all interested parties to provide comments and feedback on the areas proposed and in particular highlight how interested parties or the areas might be impacted by exploration activities. The 21 areas in the 2018 offshore petroleum exploration acreage release are located in the offshore areas of Western Australia, South Australia, Victoria and the Ashmore-Cartier Islands. These areas will enable the next wave of investment in the Australian resources sector, and the prospect of new oil, gas and condensate production.

Esso Australia Pty Ltd, in Victoria, Australia has recently been involved in the preparation of over 20 safety cases to meet both offshore (Victoria and Western Australia) [Petroleum {Submerged Lands} Act] and onshore [Victorian Occupational Health and Safety Act] regulatory requirements.This paper focusses on the development of the onshore safety cases for both Longford and Long Island Point plants to meet the Victorian Occupational Health and Safety (Major Hazard Facilities) Regulations 2000. Both plants have been granted a five-year unconditional licence to operate.The objectives of the safety case development were to ensure that Esso:addressed major hazard facilities regulatory requirements; maximised benefit from the process, and to maximise benefit from existing work; was consistent with site approach to risk assessment/ safety culture; involved appropriate workforce from all areas— operations, maintenance and technical support; enhanced the effective knowledge and understanding of the workforce; and developed a communication tool to enable ease of understanding by site personnel.Esso’s approach of using qualitative risk assessment techniques (familiar to many site personnel) enabled the process to use tools that provided ease of involvement for the non-technical or safety specialists. This paper will explain this approach in greater detail, demonstrating how this successfully met the stringent requirements of the regulations whilst providing Hazard Register documentation readily understood by the key customer— our site workforce.The hazard register clearly identifies the relevant hazards and their controls, as well as highlighting the linkages to the safety management system and documented performance standards. A comprehensive training program provides all personnel working at site with an overview of the safety case, and the necessary skills and knowledge to be able to use the safety case and hazard register to its maximum advantage. The safety case resource booklet (similar to our offshore approach) is an integral part of the training program, and provides an ongoing reference source for trainees. It continues to receive recognition by both regulators and industry.

Available data for 2018 indicates that exploration activity is on the rise in Australia, compared to 2017, and this represents a second year of growth in exploration activity in Australia. There has been an increase in area under licence by 92 000 km2, reversing the downward trend in area under licence that commenced in 2014. Since 2016, exploratory drilling within Australia has seen a continued upward trend in both the number of wells drilled and the percentage of total worldwide. Onshore, 77 conventional exploration and appraisal wells were spudded during the year. Offshore, exploration and appraisal drilling matched that seen in 2017, with five new wells spudded: two in the Roebuck Basin, two in the Gippsland Basin and one in the North Carnarvon Basin. Almost 1500 km of 2D seismic and over 10 000 km2 of 3D seismic were acquired within Australia during 2018, accounting for 2.4% and 3.9% of global acquisition, respectively. This represents an increase in the amount of both 2D and 3D seismic acquired in Australia compared with 2017. Once the 2017 Offshore Petroleum Acreage Release was finalised, seven new offshore exploration permits were awarded as a result. A total of 12 bids were received for round one of the 2018 Offshore Petroleum Exploration Release, demonstrating an increase in momentum for offshore exploration in Australia. The permits are in Commonwealth waters off Western Australia, Victoria and the Ashmore and Cartier islands. In June 2018, the Queensland Government announced the release of 11 areas for petroleum exploration acreage in onshore Queensland, with tenders closing in February/March 2019; a further 11 areas will be released in early 2019. The acreage is a mix of coal seam gas and conventional oil and gas. Victoria released five areas in the offshore Otway Basin within State waters. In the Northern Territory, the moratorium on fracking was lifted in April, clearing the way for exploration to recommence in the 2019 dry season. With the increase in exploration has come an increase in success, with total reserves discovered within Australia during 2018 at just under 400 million barrels of oil equivalent, representing a significant increase from 2017. In 2018, onshore drilling resulted in 18 new discoveries, while offshore, two new discoveries were made. The most notable exploration success of 2018 was Dorado-1 drilled in March by Quadrant and Carnarvon Petroleum in the underexplored Bedout Sub-basin. Dorado is the largest oil discovery in Australia of 100 million barrels, or over, since 1996 and has the potential to reinvigorate exploration in the region.

Recon Exploration Pty. Ltd. has successfully completed initial testing of a new method for processing and interpretation of AGSO’s (Australian Geological Survey Organization, formerly Bureau of Mineral Resources) aerial gamma‐ray spectrometer data for petroleum exploration in the Canning Basin, Western Australia and the Otway Basin, Victoria. Count‐rate data for potassium and uranium were normalized to the thorium count rate for each sample to suppress unwanted effects of variations in surface lithology or soil type, soil moisture, vegetation cover, and counting geometry. The Canning Basin test area included five producing oil fields. All except one clearly exhibit significant and characteristic radiometric anomalies which include negative normalized potassium and more positive normalized uranium values. The Otway Basin test areas included PPL-1 commercial gas production which is associated with a group of significant radiometric anomalies similar to those in the Canning Basin. These results are similar to extensive ongoing tests in the U.S. and are explained in terms of well‐understood geological, geochemical, and geophysical models. Based on 69 wells in the three test areas, it is estimated that the chance of encountering hydrocarbons (economic production or shows) in wells within the radiometrically favorable zones is about 2.6 times greater than outside the favorable areas.

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.

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.

After 35 years of successful exploration and development, the Gippsland Basin is perceived as a mature basin. Several world class fields have produced 3.6 billion (109) BBL (569 GL) oil and 5.2 TCF (148 Gm3) gas. Without additional discoveries, it is predicted that further significant decline in production will occur in the next decade.However, the Gippsland Basin is still relatively underexplored when compared to other prolific hydrocarbon provinces. Large areas are undrilled, particularly in the eastern deepwater part of the basin. Here, an interpretation of new regional aeromagnetic and deep-water seismic data sets, acquired through State and Federal government initiatives, together with stratigraphic, sedimentological and source rock maturation modelling studies have been used to delineate potential petroleum systems.In the currently gazetted deepwater blocks, eight structural trapping trends are present, each with a range of play types and considerable potential for both oil and gas. These include major channel incision plays, uplifted anticlinal and collapsed structures that contain sequences of marine sandstones and shales (deepwater analogues of the Marlin and Turrum fields), as well as large marine shale-draped basement horsts.The study has delineated an extensive near-shore marine, lower coastal plain and deltaic facies association in the Golden Beach Subgroup. These Late Cretaceous strata are comparable to similar facies of the Tertiary Latrobe Siliciclastics and extend potential source rock distribution beyond that of previous assessments. In the western portion of the blocks, overburden is thick enough to drive hydrocarbon generation and expulsion. The strata above large areas of the source kitchen generally dip to the north and west, promoting migration further into the gazetted areas.Much of the basin’s deepwater area, thus, shares the deeper stratigraphy and favourable subsidence history of the shallow water producing areas. Future exploration and production efforts will, however, be challenged by the 200–2500 m water-depths and local steep bathymetric gradients, which affect prospect depth conversion and the feasibility of development projects in the case of successful exploration.

The Australian exploration landscape experienced an escalation of unconventional activity in 2012. Drilling targeting shale oil and gas, basin-centred tight gas, and coal gas is on the increase compared to previous years. Drilling for onshore oil and large offshore gas continued to be a staple activity for the year although, in general, offshore, the number of wells drilled is continuing to decline, in line with previous years. A number of very large 3D seismic surveys were acquired in 2012 and this is hoped to provide many future drilling targets. Within Australia, 19 new offshore conventional petroleum exploration permits were awarded within the Commonwealth jurisdiction (compared to 24 in 2011), of which 15 are located in WA, two in Victoria, one in NT, and one in the Territory of Ashmore and Cartier Islands (NT). Onshore exploration tenures awarded in 2012 included four in WA, 14 in NT, six in Queensland, and nine conventional and six geothermal in SA. At least 25 3D and six 2D seismic surveys were acquired offshore in 2012, including some very large 3D marine surveys, the largest covering an area of 12,417 km2. Onshore seismic activity was highest in Queensland and SA where 33 and 11 surveys were acquired, respectively. Offshore, 21 conventional petroleum exploration wells were drilled during the year, which resulted in 11 announced discoveries. Two exploration wells, which were spudded late in 2011, were announced as discoveries early in 2012. Five wells, which were spudded in 2012, were still drilling at year end. This equates to a better than 50% technical success rate for offshore exploration drilling for all well results known at year end. All but two of these wells were located in WA waters, the others being located in NT and Victoria. Australia-wide onshore drilling was more active than in 2011 and, as is reflected in the seismic activity, the most wells (1,048) were drilled in Queensland (dominated by CSG drilling), followed by SA (77).

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2011, 29 areas in eight offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or 12 months after the release date (i.e. 13 October 2011 and 12 April 2012)–this depends on the exploration status in these areas and on data availability. The 2011 Release is the largest since the year 2000 with all 29 areas located in Commonwealth waters offshore NT, WA, Victoria and Tasmania, covering about 200,000 km2. The producing hydrocarbon provinces of the Carnarvon, Otway and Gippsland basins are represented by gazettal blocks that are located close to existing infrastructure and are supported by extensive open file data-sets. Other areas that are close to known oil and gas discoveries lie in the Caswell Sub-basin (eastern Browse Basin) and on the Ashmore Platform (northwestern Bonaparte Basin). A particular aspect of the 2011 release is provided by 13 areas in under-explored regions offshore NT and WA–all of which range from 100–280 graticular blocks in size. These areas, located in the Money Shoal, outer Browse, Roebuck, northeastern Carnarvon, Southern Carnarvon and North Perth basins, offer new opportunities for data-acquisition and regional exploration. The release of three large areas in the Southern Carnarvon and North Perth basins is supported by new data acquired and interpreted by Geoscience Australia as part of the Offshore Energy Security Program, which selected results are being presented at this year’s conference.

One of two major play fairways investigated by explorationists in the Otway Basin is the Crayfish Group system. This Tithonian-Barremian aged succession of syn-rift, continental siliciclastics was deposited in gra- ben distributed across the basin. All of the elements of a prospective petroleum province are present: lacustrine source rocks, high-quality quartzose sandstone reservoirs, and thick regional seals that are structured by both syn and post-rift tectonic events setting up a variety of play types.There has been a resurgence of drilling of Crayfish Group prospects in South Australia in the past decade. Some 24 wells penetrating the Crayfish Group have been drilled in South Australia during this period. This has resulted in the discovery of five commercial gas-fields, three non-commercial gasfields and two significant oil shows. Contrasting with this is the paucity of exploration for similar plays in the Victorian Otway Basin where, during the last decade, only six wells have penetrated the Crayfish Group, with one significant oil show recorded. With this in mind, the author has been searching for Victorian analogues of the successful Crayfish Group hydrocarbon discoveries in South Australia. This has involved defining the major Crayfish Group depocentres and evaluating their prospectivity.There are no less than 12 major Crayfish Group depocentres in the Victorian Otway Basin. Most have not been drilled, and those that are explored are rarely penetrated by more than one well. Good quality lacustrine source rocks are intersected on the flanks of these troughs and are also interpreted to exist in the troughs from seismic data. Reservoir sandstones are abundant in the Crayfish Group at a variety of stratigraphic levels in both South Australia and Victoria, as episodes of tec- tonism resulted in the influx of quartzose, high-energy fluvial sands into the Crayfish depocentres. Potential for oil and gas generation and entrapment is demonstrated for many of these graben.

The CO2CRC Otway Project continues to demonstrate that carbon capture and storage is a viable option for CO2 mitigation. The CO2CRC Otway Project is Australia’s first CO2 demonstration project, with two projects completed, involving geological storage of some 80000 tonnes of CO2 over the past 10 years. The project was initially authorised for a single stage with a finite life, but the growing requirements of the global carbon capture and storage community required further research on carbon capture and storage technologies and behaviour (via Stages 2 and 3), and so the project was extended. CO2CRC has undertaken 360-degree stakeholder engagement processes throughout the project, regularly consulting with regulators, governments, industry, partners, researchers and the community. This has been especially important as the project changed, operating in a niche space between Victorian environment, petroleum and water Acts. This process has allowed CO2CRC to contribute to alignment efforts within regulatory bodies, to enhance regulations to cover project activities, ensuring best practices are documented and observed to the satisfaction of the regulators and wider community. The Otway Basin in south-west Victoria is a region not immune to broader community concerns regarding the oil and gas and other industries. The surrounding area is predominately dairy farming, with locals relying heavily on the aquifers beneath their land. Although such a backdrop suggests potentially high levels of concern and scrutiny, especially when projects necessitate drilling or other invasive activities, the project has maintained strong local stakeholder engagement and support due to ongoing implementation and evaluation of the stakeholder management processes.

The Otway Basin is a northwest–southeast trending rift basin which spans from onshore Victoria and South Australia into the deep-water offshore. The prospective supersequences within the basin are largely of Cretaceous age that host three possible petroleum systems (Austral 1, 2 and 3). While there is production from onshore depocentres, and the inboard Shipwreck Trough, the majority of the offshore basin remains underexplored. Recent regional studies have highlighted the need for further work across the underexplored parts of the basin and here we focus on the offshore northwest Otway Basin, integrating reinterpreted historical well data, newly acquired and recently reprocessed seismic data. This new Well Folio consists of composite logs and supporting data, which includes interpreted lithologies, petrophysical analyses, the analysis of historic organic geochemistry and organic petrology. In addition, updated well markers are provided based on seismic interpretation and new biostratigraphy in key wells. This integrated study provides the basis for renewed prospectivity assessment in the northwest offshore portion of the Otway Basin.

The frontier deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania at the eastern end of Australia’s Southern Rift System. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic. The complex structural and depositional history of the basins reflects their location in the transition from an orthogonal–obliquely rifted continental margin (western–central Otway Basin) to a transform continental margin (southern Sorell Basin). Despite good 2D seismic data coverage, these basins remain relatively untested and their prospectivity poorly understood. The deepwater (> 500 m) section of the Otway Basin has been tested by two wells, of which Somerset–1 recorded minor gas shows. Three wells have been drilled in the Sorell Basin, where minor oil shows were recorded near the base of Cape Sorell–1. As part of the federal government-funded Offshore Energy Security Program, Geoscience Australia has acquired new aeromagnetic data and used open file seismic datasets to carry out an integrated regional study of the deepwater Otway and Sorell basins. Structural interpretation of the new aeromagnetic data and potential field modelling provide new insights into the basement architecture and tectonic history, and highlights the role of pre-existing structural fabric in controlling the evolution of the basins. Regional scale mapping of key sequence stratigraphic surfaces across the basins, integration of the regional structural analysis, and petroleum systems modelling have resulted in a clearer understanding of the tectonostratigraphic evolution and petroleum prospectivity of this complex basin system.

This review looks back at 2014 from a business context and considers where the Australian petroleum industry will be placed in 2015. Globally, there were a number of major developments in 2014. These included new supply sources (e.g. PNG LNG), exploration successes (e.g. Brazil), and evolving energy export policies that have been set to change the market (e.g. US, OPEC). Russia agreed to a major gas supply agreement with China, and access to talent remained an issue. In Australia, there were a number of developments that shaped the business agenda, including: Capital projects—Prelude, QCLNG, and many others—achieved major milestones such as first LNG production. There were ongoing cost increases in capital projects. From a tax perspective, the Petroleum Resource Rent Tax (PRRT) was not renounced, and a decision was made on Browse royalties. Operators were busy with commissioning teams and preparing to operate new assets. Boards debated capital management, notably the AU$200 billion of projects in pre-FID and asset divestments. Exploration, notably for onshore east coast regulations in NSW and Victoria. The opening of the Wallumbilla gas supply hub in Queensland, in March 2014. 2015 will be an important period for the industry in Australia. For instance, the price of oil will be under pressure due to the changing global market forces for energy. Operators will have to work hard in 2015 as they commission large new facilities, reduce costs, and improve plant reliability. Also, the regulatory agenda will be focused on exploration, and balancing domestic and export market forces.

The critical success factors that control hydrocarbon prospectivity in the Otway Basin have been investigated using petroleum systems approaches. It have revealed that greater than 99% of the discovered hydrocarbons in the Victorian Otway Basin have been sourced from Austral 2 (Albian-Aptian) source rocks and that these Austral 2-sourced hydrocarbon accumulations either directly overlie—or are located within 3,000 m—of actively generating Austral 2 source rock kitchens. Importantly, the zones of greatest prospectivity are located where these source rocks have been actively generating and expelling hydrocarbons throughout the Late Paleogene, primarily as a result of sediment loading associated with progradation of the Heytesbury shelfal carbonates. This peak generation window occurs at an average depth of approximately 2,500–3,500 m sub-mud across much of the basin, which has allowed prospective hydrocarbon fairways to be mapped out, thereby highlighting areas of greatest prospectivity. The close spatial proximity of the actively generating source rocks to the accumulations is due to several factors, which include overall poor fault seal in the basin (success cases occur where charge rate exceeds leakage rate) and relatively complex and tortuous migration fairways (which means that large volumes of hydrocarbons are only focussed and migrate for relatively short distances). In areas within which the Austral 2 system comprises the sole hydrocarbon charge—such as across the inner Mussel Platform—the reservoired gas compositions are typically very dry. In contrast, the gas compositions in accumulations sited along or immediately inboard of the Mussel-Tartwaup Fault Zone (La Bella, Geographe and Thylacine) are significantly wetter and also have higher CO2 contents. Throughout this area, the wetter components of the reservoired hydrocarbon inventory may have a source contribution from within the basal (Turonian) part of the younger Austral 3 system, in sequences that have been confirmed by δTLogR analysis to be significantly enriched in total organic carbon content. This observation has significantly upgraded the potential of the upper shelf areas, where a relatively more liquids-rich hydrocarbon inventory might be expected. The CO2 in accumulations located along the Mussel-Tartwaup Fault Zone is interpreted, based upon new helium isotope data, to be of mixed deep crustal-magmatic origin. This CO2 is believed to have migrated from great depth up the crustal-scale fault arrays into the shallower Late Cretaceous reservoirs. Here, the CO2 mixed with crustal gases, typified by helium with a mixed magmatic-crustal isotopic signature. Throughout this area, the traps tend to be large and hence—even though their CO2 contents are only 8–12%—the total CO2 volumes contained in these accumulations are much greater than those in the very CO2-rich—but volumetrically small traps—located onshore (e.g. Boggy Creek). Hydrocarbon accumulations located on the inner shelf, such as Minerva and Casino, have distinctly lower CO2 contents, perhaps because large displacement, through-going faults are lacking in this area. These observations collectively provide a predictive regional framework for understanding the likely distribution of commercial hydrocarbon accumulations in the offshore Otway Basin, as well as for forecasting the gas wetnesses and CO2 contents of undrilled exploration targets in both well-explored and frontier parts of the basin.

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.

Long-term studies of suspended particulate matter (SPM) and organic compounds (OCs)—Corg, lipids, hydrocarbons (aliphatic—AHCs and polycyclic aromatic—PAHs), and chlorophyll a in the snow cover of the Arctic (Franz Victoria Trough, Mendeleev Rise, White Sea) and Antarctica (in the coastal waters on fast ice and on the mainland near Russian stations) were generalized. It was shown that in the Arctic, the influence of continental air masses leads to an increase in OCs in snow. Therefore, despite the fact that the Franz Victoria Trough and the Mendeleev Rise are at the same latitude (82° N), the OCs content in the snow in the region of the Mendeleev Rise was lower for aliphatic hydrocarbons 5 and 14–18 μg/L. In the White Sea, the AHC content in the snow and the upper layers of the ice in the mouth of the Severnaya Dvina River and in the Kandalaksha Bay was higher than that in the lower layers of the ice and sharply decreased with distance from the emission sources. As a result, the snow was supplied mainly by pyrogenic PAHs. In the Antarctica, the lowest OCs levels in atmosphere were found in areas where coastal hills are covered with snow. The maximum SPM and AHCs concentration was found in the sludge (SPM—to 4.37 mg/L, AHC—to 33 μg/L). An increase in the concentration of OCs and SPM in snow sampled on the continent took place in the areas of stations and oases (St. Novolazarevskaya) where the predominance of mineral particles in the SPM was registered. In the area of the operating stations, mainly low molecular weight PAHs with the dominance of petroleum PAHs were found in the SPM of snow and in mosses.

In the post-Montara/Macondo world, the Australian petroleum industry has been actively represented on various working groups focused on the prevention, preparedness and response to significant oil spill incidents. Through the Australian Marine Oil Spill Centre (AMOSC) based in Geelong, Victoria, cooperation and coordination with other international associations has been occurring to ensure ‘reasonable steps’ are taken to develop preparedness and response arrangements commensurate with the risks associated with industry activities.Concurrently and here in Australia, a thorough review of the National Plan has allowed industry to work with government to develop or amend a range of initiatives aimed at ensuring that industry and government strategies are integrated for maximum efficiency in all circumstances. The scene has been set by a reviewed national risk assessment focusing on all activities of hydrocarbon movement around the Australian coastline. So what has Australian industry actually achieved post-Montara in prevention, preparedness and response to oil spills? This extended abstract shares and explains the practical outcomes of the industry initiatives of oil spills in Australia. The outcomes are planning requirements, equipment location, mutual aid arrangements, training programs and the extended services of industry oil spill response organisations in Australia and overseas.

Underground gas storage is becoming increasingly important in Australia with the discovery of significant gas reserves, mostly in places distant from the expanding markets for gas.Gas has been stored in the offshore Barracouta Field since 1971 and storage projects are either being considered or underway in New South Wales, South Australia, Western Australia and the Northern Territory.Although not a great deal of attention has been paid to the legal, tax and administrative aspects of underground gas storage, the position is likely to change the more it becomes apparent that such storage is commercially and technically viable.The applicable legal regime will depend on the location of the storage. Offshore gas storage on the continental shelf beyond the coastal waters of a state is subject to Commonwealth jurisdiction. In state coastal waters, it is subject to state laws. Onshore, it is subject to the jurisdiction of the state or territory in which the storage occurs.Offshore beyond state coastal waters the Australian government has sovereign rights over the continental shelf for the purposes of exploring the continental shelf and exploiting its natural resources.There are a number of legal uncertainties which arise from gas storage which will be of concern to financiers as well as gas storers. With certain exceptions, there is doubt as to ownership of stored gas, and the right to inject and store gas. The right of withdrawal however would appear to fall under the right which normally exists under a production lease to 'mine' petroleum, or to conduct 'petroleum mining operations'. Except in Victoria, and to a significantly lesser extent South Australia, there is very little legislative guidance on the topic and related issues.The question whether stored gas is trading stock is the subject of Income Tax Ruling 2190 of 10 September 1985. This puts at rest, in practical terms, in any event, some of the doubts which existed as to the characterisation for income tax purposes of gas stored near the place of original extraction — the ruling concluded that 'reinjected processed gas should not be treated as trading stock for income tax purposes'.It is concluded that there is a good case for those Australian jurisdictions in which gas storage is occurring, or is about to occur, to provide legislation to eliminate the uncertainties.

2009 saw an overall decrease from high activity from 2008, levelling off in the December quarter as the economy stabilised. Unsurprisingly, most activity was in offshore Western Australia and on coal seam methane (CSM) in Queensland. Highlights include: good results in the Carnarvon and Browse basins for Western Australian operators, interest in Karoon and Conoco-Phillips’ enigmatic Poseidon project, over 180 CSM exploration wells in Queenslandd, and a relatively busy year for Tasmania. Western Australian seismic acquisition approached 10,000 km of 2D and 25,000 km2 of 3D for 38* wells and success rate around 50%. South Australia saw the highest conventional onshore drilling and seismic activity, with good results for 17 wells, while other states saw low activity in this sector. Victoria saw one offshore exploration well and no seismic. Tasmania also saw no new seismic, but saw four exploration wells and encouragement at Rockhopper–1. CSM is picking up in South Australia, and New South Wales saw continued high CSM activity in a historically low-activity region. High success rates suggest two trends: explorers finding value in 3D seismic, and a ‘flight to quality’ as operating costs and poorer access to capital reinforce risk aversion among operators. Elsewhere, geothermal energy helped small cap investors satisfy their appetite for risk outside of the petroleum industry, and results will be watched with great interest. *Numbers are from early public and departmental statistics and may be revised.

Esso Australia Resources Pty Ltd and BHP Petroleum (Bass Strait) Pty Ltd own a range of offshore and onshore hydrocarbon production facilities, which have been operated by Esso Australia Pty Ltd (Esso) for over 50 years. The Longford Fire Training Ground (FTG) is located adjacent to the Longford Plants and has been utilised by Esso for many years to train personnel in practical hydrocarbon firefighting skills, including applying firefighting foams to extinguish liquid hydrocarbon pool fires. In line with historical standard oil-field practices, per and polyfluoroalkyl substance (PFAS) containing firefighting foams were used at the Longford FTG. In response to the reported use of these foams and the potential for contamination associated with historical site operations, the Longford premises were the subject of recent environmental audit and clean-up plans with oversight by an EPA Victoria auditor. Esso engaged a broad range of experts to complete the environmental investigation and develop a remediation action plan that complied with the PFAS National Environmental Management Plan. Key aspects of this project included: understanding the location and setting, with respect to geological conditions and groundwater impacts; development of remediation objectives and strategy; identification of practical remediation methods including short-term and longer-term measures to mitigate priority PFAS sources within the FTG; and a planning framework for future management of the premises. This paper shares how a responsible operator applies a disciplined and scientifically based environmental approach to further the state of knowledge on practical PFAS remediation methods and achieve a sustainable environmental outcome in the communities that they operate in.

Hydraulic stimulation, to increase the productivity of petroleum and geothermal wells, has been applied onshore in Australia for more than 50 years. While most states and territories have employed hydraulic stimulation, the most significant application has been in SA and Queensland, driven by the development of significant gas resources in the Cooper-Eromanga and Bowen-Surat provinces. In Queensland, some 500 wells have been hydraulically stimulated in the past five years, driven by the appraisal and development of coal seam gas (CSG) resources. As global and domestic demand for natural gas continues to grow, and in light of the recent start-up of Queensland’s liquefied natural gas (LNG) exports, industry will continue to optimise discovered resources while identifying new supply in under-explored basins and plays. Australia has substantial onshore prospective and contingent gas resources, a significant proportion of which are held in shale and tight sands. Commercialising this gas, at volumes sufficient to underpin associated major investment, will require the extensive application of hydraulic stimulation. The federal government and all states and territories bar Queensland have completed independent or parliamentary inquiries into hydraulic stimulation or unconventional gas development in general. A moratorium on hydraulic stimulation presently exists in Victoria and Tasmania. This paper summarises the historic application of hydraulic stimulation onshore Australia, the legislation presently in place to regulate and manage the activity, and a hypothetical scenario of the application of hydraulic stimulation to explore for and develop shale and tight gas resources at a field scale.

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

Woodside has been managing seismic acquisition and drilling operations as part of a gas exploration program in the offshore Otway Basin in southwest Victoria since July 1999. There are a number of sensitive and complex environmental and multiple-use issues facing companies undertaking exploration activities in these waters, including a seasonal aggregation of feeding blue whales, winter calving and breeding habitat for southern right whales and a productive rock lobster fishery. Recent changes to the legislative regime for environmental approvals of petroleum activities in Commonwealth waters has introduced further complications for operators in this area. Consequently, a key aspect of this exploration program has been the pro-active management of environmental and stakeholder issues.A comprehensive management strategy addressing these issues was developed for seismic acquisition and drilling operations, with the key objectives of ensuring regulatory compliance and facilitating a process where all stakeholders were fully informed about proposed activities. This process focussed on informing stakeholders of the potential impacts of seismic acquisition and drilling, and how Woodside intended to manage those impacts. This approach was driven by a desire for continuous improvement of performance, over and above compliance with all regulatory requirements. It also recognises the legitimacy of stakeholder risk through social, environmental and political values, and has had environmental and economic benefits for the project.Environmental benefits included early identification and assessment of potential environmental impacts resulting from the different phases of exploration, development of management strategies to control and mitigate these potential impacts, and improved environmental awareness across the project team, joint venture partners and external stakeholders. Prevention of delay or denial of regulatory approvals for exploration activities had significant economic benefits to Woodside and the joint venture partners. The development and implementation of a stakeholder involvement process, involving explorers, external affairs and environmental advisers, was an innovative approach that has application across other Woodside activities and the industry generally, particularly for projects in locations with a high level of environmental sensitivity, multiple-use and stakeholder concern.

A continuing high and stable oil price through the latter part of 2011, oscillating around US$120 in the case of Tapis Crude, underpinned a small increase in exploration in 2011 in Australia compared with 2010, although there were marked regional differences between the northwest and southeast parts of the country. Exploration continued to be focused on the northwest offshore seeking incremental reserve additions of conventional gas to support planned and proposed liquid natural gas (LNG) projects and although information is hard to confirm, in general this program appears to have been successful with a number of relatively smaller discoveries and at least one major find, Zola–1. In the Cooper Basin exploration activity resumed after almost being shut down by floods in 2010, although flooding continued to be a problem in 2011. In the South Australian part, 27 new field wildcat (NFW) wells were drilled in 2011 compared with 8 in 2010. The program was also marked by a high rate of success. The other current major area of activity, the Queensland coal seam gas (CSG) program was also affected by flooding early in 2011 with 524 coal seam gas (CSG) wells drilled this year, compared with 648 in 2010 and more than 900 in 2009. In many jurisdictions shale gas or shale oil wells are not reported separately and are included in conventional petroleum wells in this report. Exploration for geothermal resources continued at a relatively low level with only 10 wells drilled in Australia in 2011, the most active state was Victoria with five wells. Despite the increase in activity, preliminary indications are that total exploration expenditure in 2011 will be less than in 2010. It is interesting to note that while the exploration effort in terms of wells and seismic has not changed much in the last few years the total expenditure has steadily increased in part reflecting the movement into deeper water drilling.

Boral Energy Resources Ltd and its Joint Venture partners drilled two weUs in the offshore Bass Basin during 1998. Both wells targetted reservoirs in the Upper Cretaceous to Eocene Eastern View Coal Measures (EVCM).Yolla–2, located in Petroleum Licence T/RL1, appraised sandstones within the EVCM, first established gas bearing in the Yolla structure by the 1985 exploration well Yolla–1, drilled by Amoco. The exploration well White Ibis–1, located in adjacent permit T/18P, was a crestal test on a large basement high updip of the 1967 well Bass-3, drilled by Esso.Both wells of the 1998 drilling program encountered gas columns in the objective Paleocene to Lower Eocene section of the EVCM (Intra-EVCM). Liquids-rich gas was recovered from these reservoirs in wireline tests. Formation pressure data suggest a thin oil rim is developed in White Ibis–1. Neither well was tested in cased hole though White Ibis–1 was suspended for potential re-entry. Yolla–1 also encountered a gas and oil accumulation at the top of the Eastern View Coal Measures, but this level was not an objective in Yolla–2.Based on well results and 3D seismic control, a gas resource of between 450–600 BCF OGIP is currently estimated in the Yolla Field. The gas accumulation encountered in White Ibis–1 is estimated at 85 BCF OGIP.The 1998 drilling campaign has provided encour-agement to the T/RL1 and T/18P Joint Ventures to continue the search for both oil and gas in the Bass Basin. Markets for gas are being pursued in both Tasmania and Victoria and engineering studies are being undertaken in parallel to refine parameters for a potential Yolla Field development. The White Ibis Field may provide a candidate as a satellite to such a development. Depending on the outcomes of these studies, further drilling may occur in 1999 to increase confidence in the reserves base in the Yolla Field, and to further evaluate the exploration potential of T/18P.

O presente artigo procura resgatar um dos períodos mais intensos e menos estudados da Guerra Fria no Brasil, quando duas correntes militares antípodas política e ideológicas atuaram na perspectiva de influenciar através de suas entidades de classe um projeto de nação. Entretanto, essa reflexão tem por foco, os militares nacionalistas e de esquerda, oficiais e praças das forças armadas cuja intervenção foi bem sucedida ao final, com a vitória da Tese do Monopólio Estatal do Petróleo e não intervenção brasileira no conflito coreano, embora ao custo de uma repressão sobre centenas de militares, muitos deles presos e torturados e até hoje não anistiados, demonstrando em última instância, a fragilidade da democracia e do Estado Democrático e de Direito no Brasil. Abstract The Military and the Cold War in Brazil The present article seeks to recover one of the most intense and least studied period of the Cold War in Brazil, when two military antipodal political and ideological currents acted in the perspective of influencing through its class entities a nation project. However, this reflection is focused on the nationalist and leftist military, officers and squares of the armed forces whose intervention was successful in the end, with the victory of the Thesis of the State Petroleum Monopoly and not Brazilian intervention in the Korean conflict, although at cost of a crackdown on hundreds of soldiers, many of them imprisoned and tortured and still unamused, demonstrating in the last instance the fragility of democracy and the Democratic State and Law in Brazil. Resumen Los Militares y la Guerra Fría en Brasil El presente artículo busca rescatar uno del período más intensos y menos estudiados de la Guerra Fría en Brasil, cuando dos corrientes militares antípodas políticas e ideológicas actuaron en la perspectiva de influenciar a través de sus entidades de clase un proyecto de nación. Sin embargo, esta reflexión tiene por foco, los militares nacionalistas y de izquierda, oficiales y plazas de las fuerzas armadas cuya intervención fue exitosa al final, con la victoria de la Tesis del Monopolio Estatal del Petróleo y no intervención brasileña en el conflicto coreano, aunque al costo de una represión sobre cientos de militares, muchos de ellos presos y torturados y hasta hoy no aniquilados, demostrando en última instancia, la fragilidad de la democracia y del Estado Democrático y de Derecho en Brasil.

This paper provides a brief update on some of the key environmental issues that arose during 2009. In Queensland, activity is dominated by coal seam gas projects and specifically coal seam gas (CSG) to liquefied natural gas (LNG) projects. Environmental milestones for these projects are discussed, and the State Government’s response policy and regulation development response is reviewed. The progress of the more conventional LNG projects in Western Australia and the Northern Territory is also discussed. The final report on the mandated ten year review of the Environment Protection and Biodiversity Conservation Act 1999 was released in December 2009. Seventy-one recommendations were made, and some key recommendations related to our industry are discussed here. Climate change has again dominated the media, with the United Nations Climate Change Conference held in Copenhagen in December 2009. In Queensland, the Government released a paper that presented a range of strategies and policies, building on a number of existing schemes and introducing new measures. Gas is identified as a key transitional fuel while low emission coal technology and emerging renewable energy sources are being developed. Greenhouse gas legislation is continuing to be developed across several states, but subordinate legislation is yet to be finalised. In Victoria, submissions on the Greenhouse Gas Geological Sequestration Regulations closed in October 2009, and the Greenhouse Gas Geological Sequestration Act 2008 came into effect on 1 December 2009. In March 2009, ten offshore acreage releases were made under the Commonwealth legislation; however, the closing date for submissions is dependent upon the development of the regulations. South Australia passed an Act amending the Petroleum and Geothermal Act 2000 on 1 October 2009 to allow geosequestration. A number of reviews of the regulatory framework or the administrative systems associated with the upstream oil and gas sector have been completed in the last decade. All these reviews make similar findings and recommendations, and most recently the Jones Report, tabled in Western Australian Parliament on 12 August 2009, found that most key recommendations from previous reports and reviews had not been addressed or properly implemented. There seems to be little point in undertaking regulatory and system reviews that consistently make similar findings, if these findings are never addressed. The hurdles to implementation of key recommendations need to be identified, so that progress can be made in improving the approvals processes for the industry, and improving the environmental outcomes.

This article traces the rise of modern oil culture to interlocking innovations in British fiction, political economy, natural science, and colonial capitalism. It advances a method called “transitive reading” to understand those innovations and to show how writers first conceived of oil in relation to established energy inputs such as coal. The article then reads Joseph Conrad's late masterpiece, Victory (1915), as an ambivalent artifact of the British petro-imagination. In representing the “liquidation” of overseas coal capitalism, Victory articulates a desire for freedom from carbon power, while nevertheless binding that desire to a world where petroleum or “liquid coal” was becoming increasingly constitutive of the self.

The opening of 'free and fair trade' in natural gas from 1 July 1996 provides the opportunity to service Sydney and regional NSW energy markets with competitively priced Bass Strait gas.The Eastern Gas Pipeline Project (EGPP), proposed by BHP Petroleum Pty Ltd and a Canadian company, Westcoast Energy Inc, will link Victorian reserves to NSW transmission and distribution systems.The proponents have taken on a major coordination exercise to ensure that project planning, market development, communications, environmental assessment and regulatory approvals are integrated and managed against a demanding project schedule.Exposure to three regulatory jurisdictions has complicated this task.The project requires many approvals including approval under the Commonwealth government's foreign investment policy, pipeline permits and licences under Victorian and NSW Pipelines Acts and requires environmental impact assessment under Commonwealth, Victorian and NSW legislation.Early in the project's life the proponents recognised the need for a strongly coordinated approvals process and have since worked with government assessment and facilitation agencies to achieve a coordinated process. This ground-breaking project is now the subject of one Environmental Impact Assessment process, one process for public review and one coordinated decision-making process to meet the requirements of all three jurisdictions.This paper explores the challenges of coordination and suggests ways of improving future joint assessment and approval processes.

Primary Australian terrestrially-derived crudes are characterised by high wax and n-alkane contents. These characteristics, as determined by hydrogenation and hydrous pyrolysis, appear to be unrelated to either the chemical or petrographic compositions of Victorian brown coal lithotypes. Furthermore, since relationships between chemical and petrographic composition are obscure, a re-examination of current concepts which relate these established source rock parameters to liquid hydrocarbon generating potentials is warranted.The content of thermally stable, longer-chain, n-alkyl components in source rocks is introduced as the critical factor in determining whether these rocks have the potential to generate typical Australian waxy crudes or hydrocarbon gases. Modifications to this general concept are required by the thermal stability of directly substituted longer-chain n-alkyl aromatics and hydroaromatics. These appear to be sources of light hydrocarbons and gases, rather than oils.Inherent weaknesses in the experimental techniques of hydrogenation and hydrous pyrolysis have hindered the collection of data, but the concept that n-alkane potential is a critical factor in determining the petroleum-generating potential of immature source rocks is being pursued using techniques modified for the determination of their total heteroatom-bonded n-alkyl contents.

Naturally Occurring Radioactive Material (NORM) is an inevitable by-product of petroleum exploration and production. It is produced with the reservoir fluids and is typically found in low concentrations, but potentially high volumes. However, Victorian regulations that cover NORM are based on acceptable public exposure to ionising radiation and appear to be formulated around high concentration, low volume sources such as those found in medical procedures.Esso Australia Pty Ltd conducted a comprehensive exposure assessment study to establish limits for NORM. The two-year study was carried out in conjunction with the regulators (Victorian Environment Protection Authority, Department of Human Services, and Australian Radiation Protection and Nuclear Safety Agency) and included other key stakeholders like employees and suppliers.This paper provides a discussion of the management plans for, and the results of, assessments undertaken to quantify any potential risk of handling and disposing of NORM material in the environment. The assessments demonstrate that exposure to NORM released into the environment from Bass Strait oil and gas operations does not present a radiological hazard to workers, the general public, or ecological receptors. In fact, it represents less than 1% of Australian and internationally accepted limits for such exposure.

There have been several studies, both published and unpublished, of the present-day state-of-stress of southeast Australia that address a variety of geomechanical issues related to the petroleum industry. This paper combines present-day stress data from those studies with new data to provide an overview of the present-day state-of-stress from the Otway Basin to the Gippsland Basin. This overview provides valuable baseline data for further geomechanical studies in southeast Australia and helps explain the regional controls on the state-of-stress in the area.Analysis of existing and new data from petroleum wells reveals broadly northwest–southeast oriented, maximum horizontal stress with an anticlockwise rotation of about 15° from the Otway Basin to the Gippsland Basin. A general increase in minimum horizontal stress magnitude from the Otway Basin towards the Gippsland Basin is also observed. The present-day state-of-stress has been interpreted as strike-slip in the South Australian (SA) Otway Basin, strike-slip trending towards reverse in the Victorian Otway Basin and borderline strike-slip/reverse in the Gippsland Basin. The present-day stress states and the orientation of the maximum horizontal stress are consistent with previously published earthquake focal mechanism solutions and the neotectonic record for the region. The consistency between measured present-day stress in the basement (from focal mechanism solutions) and the sedimentary basin cover (from petroleum well data) suggests a dominantly tectonic far-field control on the present-day stress distribution of southeast Australia. The rotation of the maximum horizontal stress and the increase in magnitude of the minimum horizontal stress from west to east across southeast Australia may be due to the relative proximity of the New Zealand segment of the plate boundary.

Abstract The proposed petroleum developments in the Lofoten, Vesterålen, and Senja are a controversial issue in Norway. We ask how insights into legitimacy and risk perception can help to illuminate the disputed policy process for petroleum developments in Lofoten, Vesterålen, and Senja. Our Q-methodology elicits three key narratives that steer the policy process: (i) best practice and knowledge does not permit coexistence, and fishing takes priority; (ii) coexistence is possible with good process where the nation-state manages risk; and (iii) the state and industry cannot facilitate coexistence, science and conservation come first. We argue these narratives reflect divergence in worldview in three key ways: (i) differential perspectives on the priority of local, national, and global scales; (ii) emphasis on the role of knowledge, skill, and rectitude in finding best policy; and (iii) differential concern for fish, the nation-state, and conservation. We argue for a more realistic approach to coexistence in deliberative democracy that does not aim for consensus and win-win outcomes, and assert that disagreement and partial victories and losses is a natural and healthy state of affairs in a democracy.

China Shale-Gas Field Sets Production Record Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache and Total Plan Suriname Appraisals Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname. The company said another submission is expected for Kwaskwasi, the largest find in the block, by the end of the year. Operations continue for Keskesi, the fourth exploration target. There are plans to drill a fifth prospect at Bonboni in the North-Central portion of the concession. Partner company Total is assuming operatorship of the block ahead of next year’s campaigns. BP Emerges as Sole Bid for Offshore Canada Parcels BP was the only operator to place a bid in the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) Call for Bids NL20-CFB01, which offered 17 parcels (4,170,509 hectares) in the eastern Newfoundland region. The successful bid was for Parcel 9 (covering 264,500 hectares) for $27 million in work commitments from BP Canada Energy Group. Subject to BP satisfying specified requirements and receiving government approval, the exploration license will be issued in January 2021. No bids were received for the remaining 16 parcels, which may be reposted in a future Call for Bids. Criteria for selecting a winning bid is the total amount the bidder commits to spend on exploration of the parcel during the first period of a 9-year license, with a minimum acceptable bid of $10 million in work commitments for each parcel. Beach Energy To Drill Otway Basin Well Beach Energy plans to drill at its Artisan-1 well about 32 km offshore Victoria, Australia, in the Otway basin, before the end of 2021. The well, located on Block Vic/P43, was to be spudded in 1H 2020 but was delayed due to COVID-19. The timeframe for drilling was confirmed by the National Offshore Petroleum Safety and Environmental Management Authority, which also said Beach is keeping open the option to suspend the well and develop it, pending reservoir analysis. Anchors, mooring chains, and surface buoys have already been laid for the well, which is in a water depth of approximately 71 m. The well is expected to take approximately 35–55 days to drill, depending on the final work program and potential operational delays. Diamond Offshore’s semisubmersible Ocean Onyx was contracted for the drilling program. Artisan is the first of Beach’s planned multiwell campaigns, which also include development wells at the Geographe and Thylacine fields. Hess Completes Sale of Interest in Gulf of Mexico Field Hess completed the sale of its 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico (GOM) to BHP, the field’s operator, for $505 million. Shenzi is a six-lease development structured as a joint ownership: BHP (operator, 44%), Hess (28%), and Repsol (28%). The acquisition would bring BHP’s working interest to 72%, adding approximately 11,000 BOE/D of production (90% oil). The sale is expected to close by December 2020. Hess CEO John Hess said proceeds from the sale will help fund the company’s investment in Guyana. Greenland Opens New Offshore Areas Greenland opened three new offshore areas for application of oil and gas exploitation licenses off West Greenland. The areas are Baffin Bay, Disko West, and Davis Strait. The country also said it is working on an oil strategy to reduce geological uncertainty by offering an investment package to companies that engage in its Open Door Procedures. The procedures are a first-mover advantage to remove national oil company Nunaoil, as a carried partner, reducing turnover and surplus royalties. It is estimated to reduce the government take by 51.3% to 40.6%. Shell and Impact Oil & Gas Agree to South Africa Farmout Africa Oil announced Impact Oil & Gas entered into two agreements for exploration areas offshore South Africa. The company has a 31.10% share-holding in Impact, a privately owned exploration company. Impact entered into an agreement with BG International, a Shell subsidiary, for the farm-out of a 50% working interest and operatorship in the Transkei and Algoa exploration rights. Shell was also granted the option to acquire an additional 5% working interest should the joint venture (JV) elect to move into the third renewal period, expected in 2024. Algoa is located in the South Outeniqua Basin, east of Block 11B/12B, containing the Brulpadda gas condensate discovery and where Total recently discovered gas condensate. The Transkei block is northeast of Algoa in the Natal Trough Basin where Impact has identified highly material prospectivity associated with several large submarine fan bodies, which the JV will explore with 3D seismic data and then potential exploratory drilling. Impact and Shell plan to acquire over 6,000 km² of 3D seismic data during the first available seismic window following completion of the transaction. This window is expected to be in the Q1 2022. After the closing of the deal, Shell will hold a 50% interest as the operator and Impact will hold 50%. Impact also entered into an agreement with Silver Wave Energy for the farm-in of a 90% working interest and operatorship of Area 2, offshore South Africa. East and adjacent to Impact’s Transkei and Algoa blocks, Area 2 complements Impact’s existing position by extending the entire length of the ultradeepwater part of the Transkei margin. Together, the Transkei and Algoa Blocks and Area 2 cover over 124,000 km2. Area 2 has been opened by the Brulpadda and Luiperd discoveries in the Outeniqua Basin and will be further tested during 2021 by the well on the giant Venus prospect in ultradeepwater Namibia, where Impact is a partner. Impact believes there is good evidence for this Southern African Aptian play to have a common world-class Lower Cretaceous source rock, similar excellent-quality Apto-Albian reservoir sands, and a geological setting suitable for the formation of large stratigraphic traps. Following completion of the farm-in, Impact will hold 90% interest and serve as the operator; Silver Wave will hold 10%. Petronas Awards Sarawak Contract to Seismic Consortium The seismic consortium comprising PGS, TGS, and WesternGeco was awarded a multiyear contract by Petronas to acquire and process up to 105,000 km2 of multisensor, multiclient 3D data in the Sarawak Basin, offshore Malaysia. The contract award follows an ongoing campaign by the consortium in the Sabah offshore region, awarded in 2016, in which over 50,000 km2 of high-quality 3D seismic data have been acquired and licensed to the oil and gas industry to support Malaysia license round and exploration activity. The Sarawak award will allow for a multiphase program to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province). The consortium is planning the initial phases and is engaging with the oil and gas industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities. Total Discovers Second Gas Condensate in South Africa Total made a significant second gas condensate discovery on the Luiperd prospect, located on Block 11B/12B in the Outeniqua Basin, 175 km off the southern coast of South Africa. The discovery follows the adjacent play-opening Brulpadda discovery in 2019. The Luiperd-1X well was drilled to a total depth of about 3,400 m and encountered 73 m of net gas condensate pay in well-developed, good-quality Lower Cretaceous reservoirs. Following a coring and logging program, the well will be tested to assess the dynamic reservoir characteristics and deliverability. The Block 11B/12B covers an area of 19,000 km2, with water depths ranging from 200 to 1800 m. It is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR International (20%), and Main Street, a South African consortium (10%). The Luiperd prospect is the second to be drilled in a series of five large submarine fan prospects with direct hydrocarbon indicators defined utilizing 2D and 3D seismic data. BP Gas Field Offshore Egypt Begins Production BP started gas production from its Qattameya gasfield development ‎offshore Egypt in the North Damietta offshore concession. Through BP’s joint venture Pharaonic Petroleum Company working with state-owned Egyptian Natural Gas Holding Co., the field, which is ‎expected to produce up to 50 MMcf/D, was developed through a one-well subsea development and tieback to existing infrastructure.‎ Qattameya, whose discovery was announced in 2017, is located approximately 45 km west ‎of the Ha’py platform, in 108 m of water. It is tied back to the Ha’py and Tuart field ‎development via a new 50-km pipeline and connected to existing subsea ‎utilities via a 50-km umbilical. ‎BP holds 100% equity in the North Damietta offshore concession in the East Nile Delta. ‎Gas production from the field is directed to Egypt’s national grid.

El proyecto bolivariano, que irrumpe en la escena política con su victoria en las elecciones presidenciales de diciembre de 1998 ha sido muchas veces analizado en cuanto a sus logros sociales derivados de un aumento exponencial de la renta petrolera, causada por una decuplicación del precio del petróleo que representó, en su máximo histórico, alrededor del 95 por ciento del total de las exportaciones del país durante 2012. Dicha expansión promovió un fuerte crecimiento del gasto social y una transferencia de renta a los sectores de menor ingreso, a través de diversos programas sociales (misiones, entre otros). La fuerte oposición de las agrupaciones empresariales fue llevando al proceso bolivariano a una radicalización de su propuesta política, al punto de que en 2005 el proyecto bolivariano se declara a sí mismo socialista. En este trabajo se intentará hacer un análisis crítico de algunos aspectos fundamentales de la economía venezolana en el periodo bolivariano, a través de la construcción de indicadores elaborados con datos oficiales que puedan servir para mostrar algunas tendencias concretas de la economía, en el sentido de elucidar el devenir real de las propuestas discursivas bolivarianas. Siendo Venezuela un país cuyo eje central se ancla en la apropiación de la renta del suelo minera (petrolera), se hará énfasis en la evolución del curso que sigue la distribución efectiva de las divisas que el Estado venezolano maneja gracias a la exportación de hidrocarburos.

One of the Victorian Government's policies in the oil and gas area is to enhance the benefits to the State in the energy sector by assessing the nature and extent of the petroleum resources. To evaluate the production capacity of developed and undeveloped gas fields, a comprehensive study was commissioned by the DITR in 1988. The first step in a study of this type is to check the accuracy of the depth maps, to see if they adequately describe the reservoir geometry. Raypath modelling, using the Advanced Interpretation Mapping System (AIMS ? Version III), was carried out by Geophysical Services International (GSI), Sydney, on a number of selected profiles over the Snapper, Marlin-Turrum, Barracouta, Kipper and Emperor fields for the DITR. Input data for the models were extracted from the operator's maps. The software simulates the normal incidence raypaths (or wave theory solution) for all shotpoints, and from this information it generates gather records and/or synthetic seismic profiles. By comparing the model data with those from data acquisition, processing and interpretation, it was possible to check the validity of the interpretation of the reservoir's geometry. This modelling work showed that the synthetic data were comparable with the acquisition and processing data, confirming that the depth maps (tied to well control) produced by the operator using its proprietary software are adequate and most likely to represent subsurface configuration of the reservoirs.

Esso Australia Pty Ltd (Esso), in a joint venture with BHP Petroleum Pty Ltd, operates 23 oil and gas production platforms and subsea facilities off the Victorian coast near Gippsland, Australia. The underlying reservoirs have multi-darcy sands and a strong aquifer water drive, so in addition to oil and gas, the extraction activities result in substantial amounts of produced formation water (PFW). Following on-platform treatment, PFW containing a variety of hydrocarbons, ions and inorganics, such as calcium, ammonia, sulfate and trace metals, is discharged into the receiving environment. This paper reports on a study undertaken to investigate the potential effects of PFW discharges from two platforms (Tuna (TNA) and West Kingfish (WKF)) on the receiving environment. Four complementary sampling approaches were used to address the objectives of the study: (1) measure and estimate the dilution of Rhodamine FWT dye solution in the receiving environment following injection into the PFW discharge line, (2) collect and analyse undiluted PFW samples before discharge, (3) collect and analyse marine water samples from within the discharge plume and (4) collect and analyse sediment and benthic infauna samples at various distances away from platforms and at reference locations. Results indicate the rate of PFW dilution within the receiving environment is more rapid than predicted by existing numerical models and that the concentration of all analytes present in PFW were below Australian and New Zealand Environment Conservation Council (ANZECC) 2000 guideline trigger values for 80% protection; moreover, with one exception, analytes were not detected above background levels more than 59 m from the platform. With the exception of a few samples containing metals, specifically arsenic, copper, lead, zinc and nickel, concentrations of analytes in the majority of sediment samples collected were below the ANZECC 2000 and revised 2013 sediment quality guidelines. A diverse range of benthic infauna were sampled, with the abundance of a limited number of taxa influenced by distance from individual platforms. No substantial differences in abundances of benthic infauna were detected at distances greater than 1.3 km from TNA and 1.0 km from WKF, compared with reference locations. These results indicate that PFW discharges from TNA and WKF likely represent a low risk to the receiving environment.