PESA Australian exploration review 2018

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.

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Australian exploration review 2017

The APPEA Journal ◽

10.1071/aj17083 ◽

2018 ◽

Vol 58 (2) ◽

pp. 479

Author(s):

Matthew Quinn ◽

Frances Hulbert

Keyword(s):

Sharp Decrease ◽

3D Seismic ◽

The North ◽

Recoverable Reserves ◽

Seismic Acquisition ◽

Exploratory Drilling ◽

2D And 3D ◽

Exploration Activity

Seventy acreage grants were awarded in Australia during 2017, with net acreage increasing in the Canning, Bonaparte and Perth basins. More broadly, the area under licence within Australia has been reducing since 2014 and this trend continued with a reduction of just over 100 000 km2. Both 2D and 3D seismic acquisition levels decreased within Australia during 2017, on an absolute and on a percentage of worldwide basis. An uptick in exploratory drilling occurred in 2017 with the highest levels since 2014 being reached. Exploratory drilling levels in Australia also increased, in percentage terms, compared with those globally. Discovered volumes exhibited a sharp decrease with a total of 22 MMboe recoverable reserves added across 14 fields. In 2018, exploration activity is expected to increase with key wells planned in the North Carnarvon and Roebuck basins.

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EXPLORATION HIGHLIGHTS FOR 2006

The APPEA Journal ◽

10.1071/aj06056 ◽

2007 ◽

Vol 47 (2) ◽

pp. 631

Author(s):

J.E. Blevin

Keyword(s):

Oil And Gas ◽

South Australia ◽

3D Seismic ◽

Market Demand ◽

South Wales ◽

Seismic Acquisition ◽

Almost All ◽

2D And 3D ◽

Exploration Activity ◽

Carnarvon Basin

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.

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2021 Offshore petroleum exploration acreage release

The APPEA Journal ◽

10.1071/aj20191 ◽

2021 ◽

Vol 61 (2) ◽

pp. 291

Author(s):

Paul Trotman

Keyword(s):

Manufacturing Industry ◽

Oil And Gas ◽

Domestic Demand ◽

Liquefied Natural Gas ◽

Petroleum Exploration ◽

Demand Growth ◽

Regulatory Frameworks ◽

The Future ◽

Policy Work ◽

Offshore Petroleum

In 2020, the liquefied natural gas (LNG) trade saw a modest increase of 1%, which is in contrast to the strong growth of previous years. Recently, the global LNG trade has picked up following the easing of impacts from the pandemic and demand growth in Asia. An increase of 6% in the global LNG trade is expected in 2021 and 2022. Domestic demand for gas remains high, with gas being used both for residential supply and also as an essential feedstock for the manufacturing industry. With a projected domestic gas shortfall, the future exploration and development of oil and gas will play a key role in ensuring access to secure, reliable and affordable energy in the future as well as assisting economic recovery from the pandemic. The importance of remaining an attractive investment destination is essential. Our challenge is to not only strike the balance of being agile and adaptive to market disruptions but also provide robust policy and regulatory frameworks to underpin future investment in the sector. Against this backdrop, this paper provides details of the 2021 offshore petroleum exploration acreage release and information about the ongoing policy work of the department.

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Proper Use of Technical Standards in Offshore Petroleum Industry

Journal of Marine Science and Engineering ◽

10.3390/jmse8080555 ◽

2020 ◽

Vol 8 (8) ◽

pp. 555 ◽

Cited By ~ 1

Author(s):

Dejan Brkić ◽

Pavel Praks

Keyword(s):

Large Scale ◽

Oil And Gas ◽

Petroleum Industry ◽

Health And Safety ◽

Oil And Gas Industry ◽

European Economic Area ◽

The European Union ◽

Technical Standards ◽

The North ◽

Offshore Petroleum

Ships for drilling need to operate in the territorial waters of many different countries which can have different technical standards and procedures. For example, the European Union and European Economic Area EU/EEA product safety directives exclude from their scope drilling ships and related equipment onboard. On the other hand, the EU/EEA offshore safety directive requires the application of all the best technical standards that are used worldwide in the oil and gas industry. Consequently, it is not easy to select the most appropriate technical standards that increase the overall level of safety and environmental protection whilst avoiding the costs of additional certifications. We will show how some technical standards and procedures, which are recognized worldwide by the petroleum industry, can be accepted by various standardization bodies, and how they can fulfil the essential health and safety requirements of certain directives. Emphasis will be placed on the prevention of fire and explosion, on the safe use of equipment under pressure, and on the protection of personnel who work with machinery. Additionally considered is how the proper use of adequate procedures available at the time would have prevented three large scale offshore petroleum accidents: the Macondo Deepwater Horizon in the Gulf of Mexico in 2010; the Montara in the Timor Sea in 2009; the Piper Alpha in the North Sea in 1988.

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SELECTING THE WINNING BID

The APPEA Journal ◽

10.1071/aj01029 ◽

2002 ◽

Vol 42 (1) ◽

pp. 523

Author(s):

E. Alexander ◽

J. Morton

Keyword(s):

Scoring System ◽

Net Present Value ◽

South Australia ◽

Petroleum Exploration ◽

3D Seismic ◽

Management Philosophy ◽

Work Program ◽

Single Target ◽

2D And 3D ◽

Selection Of

Work program bidding is established as the favoured method of allocating petroleum exploration tenements in offshore Australian waters and most of onshore Australia. However, the selection of winning bids can be complicated by the ranking of 2D versus 3D seismic, seismic versus drilling, program timing issues etc. On occasion the selection of the winning bids has been contentious. This paper summarises the process developed by the Petroleum Group in South Australia to select the winning work program bids for prospective onshore blocks for which bids have been gazetted. No other Australian jurisdiction has yet publicly released their detailed bid assessment processes.Onshore acreage releases with work program bidding have been used in South Australia since the 1980s by Petroleum Group to:focus industry onto specific prospective areas of the State (e.g. the Cooper Basin post expiry of PELs 5 and 6 in 1999); maximise exploration commitments; and achieve competition policy.The South Australian Petroleum Act 2000 allows cash or work program bidding to be used depending on the acreage. Acreage releases are announced by Ministerial press release. Associated clear bid assessment criteria are published together with promotional material to aid applicants. The date and time for close of bidding are also established, usually allowing a 6–9 month acreage evaluation period, the timeframe depending on the volume of data involved, i.e. the exploration maturity of the area.Applications received as a result of a gazettal process (i.e. competing bids) are assessed by a process designed to ensure probity and to achieve the over-arching aim of the bidding process i.e. the suitability of the applicants proposed work program for evaluating the prospectivity of the licence area and discovering petroleum.A scoring system has been developed which establishes, for each bid what is effectively a risked net present value in well equivalents. In this system, guaranteed work scores higher than non-guaranteed work; early work scores higher than later work; wells with multiple targets are scored higher than single target wells; 2D and 3D seismic and other exploration activity is converted into well equivalents; and loading of the later, non-guaranteed years of work programs are heavily discounted.The scoring system may also take into account differences in the amount and density of exploration data and minor variations may be made to the system to take this into account. It is intended that details of the scoring system to be used in bid assessment will be published each time bids are sought to ensure transparency and a level playing field.Comparisons are made with acreage management philosophy and processes used by other regulatory regimes in Australia and internationally.

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The Latrobe Group and the 90-million-year beach

The APPEA Journal ◽

10.1071/aj12071 ◽

2013 ◽

Vol 53 (2) ◽

pp. 460

Author(s):

Nick Hoffman ◽

Natt Arian

Keyword(s):

Sea Level ◽

Co2 Storage ◽

Hydrocarbon Exploration ◽

Petroleum Exploration ◽

3D Seismic ◽

Fluvial Systems ◽

Detailed Understanding ◽

Marine Embayment ◽

Gippsland Basin ◽

Lake Systems

Carbon dioxide geosequestration requires a detailed understanding of the whole sedimentary section, with particular emphasis on topseals and intraformational seals. Hydrocarbon exploration is more focused on reservoirs but requires a similar basin understanding. This extended abstract reviews the knowledge gained from petroleum exploration in the Gippsland Basin to The CarbonNet Project’s exploration program for CO2 storage. The Ninety Mile Beach on the Gippsland coast is a prominent modern-day sand fairway where longshore drift transports sediments north-eastwards along a barrier-bar system, trapping lake systems behind the coastal strip. This beach is only 10,000 years old (dating to the last glacial rise of sea level) but is built on a platform of earlier beaches that can be traced back almost 90 million years to the initiation of Latrobe Group deposition in the Gippsland Basin. Using a recently compiled and open-file volume of merged 3D seismic surveys, the authors show the evolution of the Latrobe shoreline can be mapped continuously from the Upper Cretaceous to the present day. Sand fairways accumulate as a barrier-bar system at the edge of a steadily subsiding marine embayment, with distinct retrogradational geometries. Behind the barrier system, a series of trapped lakes and lagoons are mapped. In these, coal swamps, extensive shales, and tidal sediments were deposited at different stages of the sea-level curve, while fluvial systems prograded through these lowlands. Detailed 3D seismic extractions show the geometry, orientation and extent of coals, sealing shales, fluvial channels, and bayhead deltas. Detailed understanding of these reservoir and seal systems outlines multi-storey play fairways for hydrocarbon exploration and geosequestration. Use of modern basin resource needs careful coordination of activity and benefits greatly from established data-sharing practices.

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The 2017 offshore acreage release areas: petroleum geological overview

The APPEA Journal ◽

10.1071/aj16029 ◽

2017 ◽

Vol 57 (2) ◽

pp. 304

Author(s):

Thomas Bernecker ◽

Steve Abbott ◽

George Bernardel ◽

Megan Lech ◽

Ryan Owens ◽

...

Keyword(s):

Information Management System ◽

Petroleum Exploration ◽

Seismic Survey ◽

Data Repository ◽

Technical Program ◽

North East ◽

The North ◽

Eastern Australia ◽

Northern Carnarvon Basin ◽

Offshore Petroleum

In 2017, 21 new offshore petroleum exploration areas have been released. The majority of the areas are located along the North West Shelf spanning the Westralian Superbasin from the Bonaparte Basin in the north-east to the Northern Carnarvon Basin in the south-west. New areas have been released in offshore south-eastern Australia with new opportunities provided in the Otway, Bass and Gippsland basins. Two large areas in the northern Perth Basin, an offshore frontier, complete the 2017 Acreage Release. All Release Areas are supported by industry nominations and one new cash bid area has been offered in the Dampier Sub-basin. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies. A new regional 2D seismic survey was acquired in the Houtman Sub-basin of the Perth Basin, forming the basis of the latest prospectivity study carried out by Geoscience Australia. The results of the study are presented in the technical program of the 2017 APPEA conference. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGSSA) are made available through the National Offshore Petroleum Information Management System (NOPIMS). Additional datasets are accessible through Geoscience Australia’s data repository.

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CarbonNet progress towards a declaration of identified storage formation at the Pelican site with a new high-resolution 3D seismic dataset

The APPEA Journal ◽

10.1071/aj19032 ◽

2020 ◽

Vol 60 (2) ◽

pp. 718

Author(s):

Nick Hoffman

Keyword(s):

High Resolution ◽

Greenhouse Gas ◽

Oil And Gas ◽

Co2 Storage ◽

Gas Storage ◽

Frequency Resolution ◽

Seismic Survey ◽

3D Seismic ◽

Long Term Storage ◽

Gippsland Basin

The CarbonNet project is making the first ever application for a ‘declaration of an identified greenhouse gas storage formation’ (similar to a petroleum location) under the Offshore Petroleum and Greenhouse Gas Storage Act. Unlike a petroleum location, however, there is no ‘discovery’ involved in the application. Instead, a detailed technical assessment is required of the geological suitability for successful long-term storage of CO2. The key challenges to achieving a successful application relate to addressing ‘fundamental suitability determinants’ under the act and regulations. At Pelican (Gippsland Basin), a new high-resolution 3D seismic survey and over 10 nearby petroleum wells (and over 1500 basinal wells) supplement a crestal well drilled in 1967 that proved the seal and reservoir stratigraphy. The GCN18A 3D marine seismic survey has the highest spatial and frequency resolution to date in the Gippsland Basin. The survey was acquired in water depths from 15 to 35 m with a conventional eight-streamer seismic vessel, aided by LiDAR bathymetry. The 12.5 m bin size and pre-stack depth migration with multiple tomographic velocity iterations have produced an unprecedented high-quality image of the Latrobe Group reservoirs and sealing units. The 3D seismic data provides excellent structural definition of the Pelican Anticline, and the overlying Golden Beach-1A gas pool is excellent. Depositional detail of reservoir-seal pairs within the Latrobe Group has been resolved, allowing a confident assessment of petroleum gas in place and CO2 storage opportunities. The CarbonNet project is progressing with a low-risk storage concept at intra-formational level, as proven by trapped pools at nearby oil and gas fields. Laterally extensive intra-formational shales provide seals across the entire structure, providing pressure and fluid separation between the overlying shallow hydrocarbon gas pool and the deeper CO2 storage opportunity. CarbonNet is assessing this storage opportunity and progressing towards a ‘declaration of an identified greenhouse gas storage formation’.

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Quaternary evolution of the northern North Sea

10.5194/egusphere-egu2020-10118 ◽

2020 ◽

Author(s):

Christine Batchelor ◽

Dag Ottesen ◽

Benjamin Bellwald ◽

Sverre Planke ◽

Helge Løseth ◽

...

Keyword(s):

North Sea ◽

Seismic Data ◽

3D Seismic ◽

Quaternary Sediments ◽

The North ◽

The North Sea ◽

Data Coverage ◽

Northern North Sea ◽

2D And 3D ◽

3D Seismic Data

<p>The North Sea has arguably the most extensive geophysical data coverage of any glacier-influenced sedimentary regime on Earth, enabling detailed investigation of the thick (up to 1 km) sequence of Quaternary sediments that is preserved within the North Sea Basin. At the start of the Quaternary, the bathymetry of the northern North Sea was dominated by a deep depression that provided accommodation for sediment input from the Norwegian mainland and the East Shetland Platform. Here we use an extensive database of 2D and 3D seismic data to investigate the geological development of the northern North Sea through the Quaternary.</p><p>Three main sedimentary processes were dominant within the northern North Sea during the early Quaternary: 1) the delivery and associated basinward transfer of glacier-derived sediments from an ice mass centred over mainland Norway; 2) the delivery of fluvio-deltaic sediments from the East Shetland Platform; and 3) contourite deposition and the reworking of sediments by contour currents. The infilling of the North Sea Basin during the early Quaternary increased the width and reduced the water depth of the continental shelf, facilitating the initiation of the Norwegian Channel Ice Stream.</p>

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AN HISTORIC GEOLOGY OF THE GIPPSLAND BASIN

The APPEA Journal ◽

10.1071/aj69011 ◽

1970 ◽

Vol 10 (1) ◽

pp. 70

Author(s):

L. C. P. Wooldridge ◽

W. G. Hill

Keyword(s):

Oil And Gas ◽

Flood Plain ◽

Main Body ◽

Deltaic Plain ◽

North West ◽

The North ◽

Channel Belt ◽

Muddy Sediments ◽

Gippsland Basin ◽

Regressive Phase

The Mesozoic and Tertiary rocks of the Gippsland Basin form a simple natural sequence as the deposits of a main regressive - transgressive cycle, followed by a regressive phase of lesser magnitude.After a period of early Mesozoic erosion in Gippsland, a river flowing from the north-west built extensive deposits which drove the sea back well beyond the present coast line. Strzelecki Formation is the name applied to the flood-plain sediments of this period. The channel belt deposits have been given various names and of these the Childers Formation appears to be the most valid. However, with the deltaic plain deposits, it can be regarded as forming a part of the Latrobe Valley Complex.About the end of Mesozoic time the sea began to transgress, also at this time there was some vulcanism in the western part of the basin. As transgression proceeded, the delta became digitate in form, similar to today's Mississippi delta. Silty and muddy sediments accumulated beyond the distributaries and between them, whilst the distributaries were areas of dominantly sand desposition. Marine agencies reworked some of the sand to form beaches and occasional barrier islands.As the sea transgressed the prodelta silty muds (Lakes Entrance Formation), covered the submerged distributaries and these in turn became covered by the cleaner water calcareous deposits of the Lower Gippsland Limestone. Meanwhile onshore, the flood-plain and earlier channel-belt deposits became overlain by later channel-belt deposits, and then by deltaic plain deposits with abundant coal. Transgression reached its zenith, probably during Miocene time, and a final regressive phase culminated in the situation as we see it today.The formation water in the main body of the Latrobe Valley complex is very fresh, and calculations show a static situation for both the Latrobe Valley and the contiguous glauconitic sandstone member, and thus the existence of down-dip escape is most unlikely. The oil at Lakes Entrance has not been flushed down-dip, rather it has moved up-dip.It follows from a consideration of the depositional history in Gippsland that producing structures at the top Latrobe Valley level are basically stratigraphic traps. They lie along ancient distributary channel trends and are flanked by contemporaneous muddy facies. Separate closures along the trends have been brought about by the development of saddles due to differential compaction and probably normal faulting at depth.The oil and gas pools today are more or less at their greatest depth of burial. An association is obvious between depth and hydrocarbon content for the top Latrobe Valley pools. A progression is noted from dry gas at Golden Beach (2,000') to a thick oil i Halibut (8,000'). Coal rank increases with depth. It is concluded that coal is the main hydrocarbon source in Gippsland. Thus all the Latrobe Valley section is prospective. The top Latrobe Valley horizon is probably the most productive to date because it has very effective cappingBarracouta 1, intersected a barrier island sand. There is likely to be more of these parallel to ancient shorelines. They could prove productive.

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