Journal articles on the topic 'Australia, Southeastern Discovery and exploration'

Exploration of poorly known regions of the Australian continental margin has resulted in the discovery of two new species in the scale worm family Eulepethidae. Grubeulepis kurnai sp. nov. occurs in southeastern Australia while Proeulepethus payungu sp. nov. was collected at one site in the Indian Ocean on the continental margin of Western Australia. Pareulepis malayana (Horst, 1913), also collected from the continental margin of Western Australia, is newly recorded from Australia, representing a range extension of that species previously known from Madagascar, Malaysia and the South China Sea. Four species, and four of the six known genera of Eulepethidae are now known from Australian waters. The family Eulepethidae remains species-poor compared with most polychaete families, and now comprises 21 species world wide.

It is now 39 years since the first gas was discovered in Bass Strait’s Gippsland Basin. Advances in exploration and production technology mean that today Australia’s longest producing offshore basin is also one of Australia’s most prospective. Gippsland is now producing around 160,000 barrels of crude and 570 million cubic feet of gas per day. To date it has produced more than 3.5 billion barrels of oil and 5 trillion cubic feet of gas and the value of the infrastructure in place is estimated to be around A$16 billion.Australia’s evolving energy market means that gas demand continues to grow. Following the re-structuring of energy markets in southeastern Australia and the installation of new pipeline infrastructure, Gippsland gas now flows to Victoria, NSW, Tasmania and will supply into South Australia from 2004. To meet this growing demand the Esso/BHPBilliton joint venture partners are investing heavily and utilising a vast array of 3D exploration technology to unlock new opportunities. In 2002 they conducted the largest 3D survey ever undertaken in Bass Strait and expect to conduct another in early 2003. A program of exploration drilling is expected to commence in late 2003. With expanded market opportunities and a gas resource base of more than 5 trillion cubic feet, the future looks bright for Gippsland.

Origin Energy Resources Limited has been an active explorer of the onshore Otway Basin in southeastern Australia for over a decade. Since 1989, the company has acquired 1,893 km and 358 sq km of 2D and 3D seismic data respectively, and participated in the drilling of 21 exploration and appraisal wells, 18 of which it operated, at a net cost of over $25 million.The primary exploration targets have been fluvial sandstones developed axially in a series of elongate half grabens that formed in initial response to the separation of the continents of Australia and Antarctica in the Late Jurassic to Early Cretaceous. The most significant of these depocentres, in terms of established hydrocarbon potential, is the highly faulted, NW–SE trending Penola Trough where these reservoirs are informally referred to as the Sawpit Sandstone and the Pretty Hill Sandstone.As the company’s geological understanding of the Penola Trough improved over time, so its exploration efforts were rewarded with new commercial discoveries at Haselgrove, Haselgrove South and Redman, and through successful appraisal of Ladbroke Grove. With respect to the application of advanced technology, 2D and 3D seismic are now subjected to Prestack Depth Migration to improve imaging of the subsurface, and Amplitude Versus Offset, Seismic Variance, Seismic Attribute, Fault Analysis and 3D Visualisation processing and/or software are also used in an integrated manner to facilitate interpretation of these data sets. Nuclear magnetic resonance logs are run in most wells to characterise gas-bearing reservoirs.Technology, respect and persistence have all played key roles in optimising the exploration process. So too have corporate teamwork and collaborative research with representatives from academic institutions and government agencies, and with industry consultants and contractors. The complex interplay between many of these success factors is illustrated by way of a case history, specifically that of the discovery and commercialisation of a low quality gas resource at Ladbroke Grove.In the fullness of time, the company is confident that further exploration success in the onshore Otway Basin will see new market opportunities addressed in terms of both gas and electricity supply. It is also hopeful that oil will eventually be found in commercial quantities.

The Stag Oilfield is located approximately 65 km northwest of Dampier and 25 km southwest of the Wandoo Oilfield near the southeastern margin of the Dampier Sub-basin, on the North West Shelf of Western Australia,.The Stag-1 discovery well was funded by Apache Energy Ltd (formerly Hadson Energy Ltd), Santos Ltd and Globex Far East in June 1993 under a farmin agreement with BHP Petroleum Pty Ltd, Norcen International Ltd and Phillips Australian Oil Co. The well intersected a gross oil column of 15.5 m within the Lower Cretaceous M. australis Sandstone. The oil column intersected at Stag-1 was thicker than the pre-drill mapped structural closure.A 3D seismic survey was acquired over the Stag area in November 1993 to define the size and extent of the accumulation. Following processing and interpretation of the data, an exploration and appraisal program was undertaken. The appraisal wells confirmed that the oil column exceeds mapped structural closure and that there is a stratigraphic component to the trapping mechanism. Two of the appraisal wells were tested; Stag-2 flowed 1050 BOPD from a 5 m vertical section and Stag-6 flowed at 6300 BOPD on pump from a 1030 m horizontal section.Evaluation of the well data indicates the M. australis Sandstone at the Stag Oilfield is genetically related to the reservoir section at the Wandoo Oilfield. The reservoir consists of bioturbated glauconitic subarkose and is interpreted to represent deposition that occurred on a quiescent broad marine shelf. Quantitative evaluation of the oil-in-place has been hampered by the effects of glauconite on wireline log, routine and special core analysis data. Petrophysical evaluation indicates that core porosities and water saturations derived from capillary pressure measurements more closely match total porosity and total water saturation than effective porosity and effective water saturation.A development plan is currently being prepared and additional appraisal drilling in the field is expected.

A record level of offshore exploration activity was achieved during 1998, despite a significant fall in the oil price. Seventyfour offshore wells were drilled, far exceeding the previous record of 64 wells achieved in 1990. Conversely, only 94 onshore exploration wells were drilled during the year, 25 fewer than in 1997, resulting in a slight reduction in the total exploration wells drilled from 176 in 1997 to 168 in 1998, following what had been a steady increase since 1992. Seismic acquisition in 1998 was also at a record level, twice that recorded in 1997. In contrast, the final quarter of 1998 may reflect the reduced activity forecast by industry, with less exploration wells spudded and almost 10,000 line-km fewer than that shot during the 1997 December quarter.This increased offshore exploration activity was rewarded with several discoveries and appraisal successes. The Carnarvon Basin was again the most successful area for offshore exploration in 1998, with 35 wells spudded during the year. The discoveries included Gipsy–1, Rose–1, Lee–1, John Brookes–1, Vincent–1, Caribou–1, Legendre South–1 and Mutineer–IB. In addition, significant successful appraisal drilling included two Gorgon wells, Egret–2, Dockrell–2 and Woollybutt–2A ST1.The Cooper/Eromanga Basin continued to be the focus of onshore exploration in Australia. Fifty-two exploration wells were spudded during the year. Discoveries were heavily weighted toward gas, with only one oil discovery in the basin, Chilla–1. The most significant gas discoveries included Verona–1 and Cabernet–1.Other important oil and gas discoveries and appraisal successes occurred in the Bonaparte Basin, at Sunset West–1, Sunrise–2 and Evans Shoal–2; in the Browse Basin, at Caspar–IA and two of the Cornea wells; in the Otway Basin, at Killanoola–l/DWl; in the Bass Basin, at White Ibis–1; in the Bowen Basin, at Yandina–2; and in the Surat Basin, at Digger–1 and West Noorindoo–1. Three significant appraisal wells were drilled in Papua New Guinea during 1998: Hides–4 proved continuity of the Hides Field over a distance of 12.6 km, Moran–4X extended the Moran Field to the northwest and Moran- 5X constrained the southeastern extent of the field. There were also significant discoveries in two New Zealand basins and these are covered in greater detail in Plume (1999).The lower oil price presents a challenge for the industry to maintain these high levels of exploration activity. New technology and better data quality have allowed re- interpretation of previously uneconomic or sub- commercial discoveries to successfully confirm the existence of economic fields. Several of the recent commercial discoveries followed up uncommercial discoveries drilled as much as 30 years earlier and have highlighted the fact that potential still exists in these areas. Improved subsurface imaging through 3D seismic acquisition, high-resolution processing, pre-stack depth migration and advanced time-to-depth conversion together with improved geological understanding has contributed to many of the successful wells drilled in 1998.

Many of the commercial hydrocarbon accumulations discovered to date within the Pretty Hill Formation in the onshore Otway Basin of southeastern Australia rely on a semi-brittle top seal and fault seal. Therefore a detailed and integrated fault, stress field and fracture analysis is fundamental to prospect evaluation.A syn-kinematic interpretation of the 3D seismic data set, using variance cube and visualisation technology was augmented with interpretation of the dip-meter and high-resolution borehole images. This resulted in the interpretation of a more complex fault history than previously inferred from 2D seismic mapping and dipmeter analysis alone.There are two major prospect/field bounding fault sets within the Penola Trough. Northwest-trending faults are associated with two commercial fields and several palaeo-accumulations. East-west trending faults are associated with three major fields, two uneconomic fields and two possible palaeo accumulations.Hydrocarbon leakage is probably caused by the creation of structural permeability across the regional seal. The location of leakage depends on the interaction between the seal, associated faults, and the regional stress field. Faults deflect regional stress trajectories within the top seal, creating local areas of high differential stress which enables brittle failure and the development of structural permeability. Predicting stress trajectories, the magnitude of differential stress and thus the location of structural permeability within the top seal to the underlying Pretty Hill Formation reservoirs, will reduce exploration risk uncertainty.

SUMMARY The variation of temperature in the crust is difficult to quantify due to the sparsity of surface heat flow observations and lack of measurements on the thermal properties of rocks at depth. We examine the degree to which the thermal structure of the crust can be constrained from the Curie depth and surface heat flow data in Southeastern Australia. We cast the inverse problem of heat conduction within a Bayesian framework and derive its adjoint so that we can efficiently find the optimal model that best reproduces the data and prior information on the thermal properties of the crust. Efficiency gains obtained from the adjoint method facilitate a detailed exploration of thermal structure in SE Australia, where we predict high temperatures within Precambrian rocks of 650 °C due to relatively high rates of heat production (0.9–1.4 μW m−3). In contrast, temperatures within dominantly Phanerozoic crust reach only 520 °C at the Moho due to the low rates of heat production in Cambrian mafic volcanics. A combination of the Curie depth and heat flow data is required to constrain the uncertainty of lower crustal temperatures to ±73 °C. We also show that parts of the crust are unconstrained if either data set is omitted from the inversion.

Note: This article is condensed from a key­note address, Transforming the Business of Gold Exploration, presented at the NewGen-Gold 2017 Conference in Perth, Australia, on November 14, 2017. Permission to adapt the published article was kindly provided by Keith Yates & Associates Pty Ltd and Paydirt Media Pty Ltd. NewGenGold conferences have been held every two years since 1995 to document case histories of discovery and to provide exploration geologists with valuable insights into the discovery process.

Geophysical observations began in Australia with the arrival of the first European explorers in the late 18th Century and there have been strong connections with European and North American geophysics ever since, both in academic and exploration geophysics. Government institutions, particularly the Bureau of Mineral Resources, have played a large part in the development of the subject in Australia, certainly more so than in North America. Academic research in geophysics has been dominated by that at the Australian National University. Palaeomagnetic research at the Australian National University has been particularly valuable, showing the large northerly drift of the continent in Cainozoic times as part of the Australia-India plate. Heat flow, electrical conductivity and upper mantle seismic velocities have been shown to be significantly different between Phanerozoic eastern Australia and the Western Shield. Geophysical exploration for metals and hydrocarbons began in the 1920s but did not develop strongly until the 1950s and 1960s. There are relatively few Australian geophysical companies and contracting companies, and instrumentation from North America and Europe have played an important role in exploration. Exploration for metals has been hampered by the deep weathered mantle over much of the continent, but the development of pulsed (transient) electromagnetic methods, including an Australian instrument (SIROTEM), has improved the situation. Geophysics has been important in several discoveries of ore-bodies. In hydrocarbon exploration the introduction of common depth point stacking and digital recording and processing in reflection surveys have played an important part in the discovery of offshore and onshore fields, as in other countries.

Exploration is vital for the continued discovery and development of the nation’s petroleum resources – resources that are essential for energy security, economic growth, long-term regional development and jobs, improved infrastructure, and value-adding to our manufacturing industries. Governmental authorities across Australia recognise the importance of a strong exploration sector, and the Commonwealth, states and territories have several initiatives to encourage exploration.

Three cycles of successful commercial hydrocarbon exploration and discovery have occurred in Australia since 1960, although sporadic efforts to locate oil accumulations have occurred since 1860. The first cycle of successful exploration, from 1960 to 1972, revealed most of the productive basins and all of the giant oil fields found to date. After an interval of very low drilling rates between 1973 and 1978, exploration activity returned to strong levels for a second cycle of discovery between 1978 and 1988. A third cycle commenced in 1989 when there was an increase in exploration activity and the number of hydrocarbon discoveries again, after a low point in the mid 1980s.The discovery of oil and gas fields is dependent on the rate of exploration activity, geological endowment, exploration efficiency and chance. Technology and geological knowledge influence exploration efficiency. The main driver of exploration activity is the profit motive, which is modified by government policies, oil price, markets, and perceived prospectivity. Discovery itself is a powerful stimulus to further exploration. Through the last 40 years these factors have varied in their impact on exploration and the resulting petroleum discoveries.

The Canning Basin in northern Western Australia is a large, relatively remote, mainly desert-covered Phanerozoic basin covering 595 000 sq km. Aborigines probably first entered the basin area 30-40 000 years ago, but the main European expeditions were not until the nineteenth and twentieth centuries. Geological exploration in the basin has been largely devoted to the discovery and exploitation of natural resources, primarily oil. Earliest geological traverses were conducted by geologists of the Geological Survey of Western Australia (GSWA). The accidental discovery of traces of oil in a water well in 1919 in the northern part of the basin diverted exploration to assessment of sediments and structures for petroleum potential. The earliest phase of oil exploration was a pioneering phase, concentrating on surface mapping and surface delineated structures as drilling sites, that was dominated by the Freney Kimberley Oil Company. West Australia Petroleum Ltd became the most active oil exploration company in the 1950s, 1960s and 1970s, using geophysics as an exploration tool in petroleum search in the basin. The late 1970s and 1980s saw an influx of companies and the application of diverse scientific approaches to the oil search. Persistence was rewarded in 1981 and 1982 with the discovery of the Blina and Sundown fields, small commercial oil accumulations. Commonwealth Government involvement in exploration was initially in the form of financial aid to exploring companies or commissioning specialist consultants for special studies. In the 1940s and 1950s and again in the 1970s the Bureau of Mineral Resources carried out basin-wide regional geological mapping in conjunction with the GSWA; onshore and offshore geophysical surveys were conducted until the 1970s. Exploration has revealed exploitable resources in the basin besides oil - diamonds, lead-zinc, coal, salt, phosphate, uranium, and heavy minerals. Only lead-zinc has present economic viability.

Petroleum exploration and appraisal activity increased in 2021. Exploration spend increased for the year, continuing a positive trend. Onshore exploration and appraisal activity continues to dominate the petroleum exploration scene in Australia. Positive indications of increased work program bids (wells, seismic and spend) are, however, tempered by the downward trend of total exploration acreage (by area) and new acreage awards. In addition to petroleum exploration acreage, greenhouse gas sequestration acreage was released across Australia in 2021. Twenty-nine exploration wells were drilled in the year compared to twenty-five in the previous year. Eight conventional petroleum discoveries were reported, with the Artisan-1 discovery in the Otway Basin being the only offshore discovery. The Lockyer Deep-1 gas discovery in the Northern Perth Basin continues the exploration success of the Permian Kingia and High Cliff Sandstone play. The Cooper–Eromanga Basin continues to yield discoveries with the Odin-1, Rosebay-1, Lowry South, Liger-1 and Chimera-1 discoveries reported for the year. Thirty-one appraisal wells were drilled for the year with significant activity in the Northern Perth Basin, Cooper-Eromanga Basin and Bowen-Surat Basins. Exploration and appraisal drilling also continued in the Beetaloo Sub-basin with the drilling of the Tanumbirini-2H, Tanumbirini-3H and Carpentaria-2/2H wells during the year.

Offshore exploration in the Exmouth Gulf commenced with seismic surveys during the early 1960s and resulted in the first well Bundegi-1 being drilled in 1978. This well, situated on the Rivoli-Bundegi Trend, encountered an interpreted residual hydrocarbon zone in the Birdrong Sandstone, an 18 m untested hydrocarbon zone in the Learmonth Formation, and tight, possibly gas bearing sandstones in the Mungaroo Formation.Modern shallow-water marine seismic data acquired by the EP 325 Joint Venture during surveys in 1987 and 1988 allowed accurate mapping of the basal Cretaceous section and the distribution of the Birdrong Sandstone. Complex structuring in the Jurassic and Triassic section was also resolved with the modern data.The Rivoli gas discovery, approximately 4.5 km northeast of Bundegi-1, was made in August 1989, with the intersection of a 10.5 m hydrocarbon column consisting mainly of gas but with a very thin oil leg (0.2 m). The Birdrong Sandstone reservoir comprises 10 m of fluvial sandstones overlain by 7 m of marginal marine sandstones and provides an important calibration point for depositional environments in this unit. The Rivoli gas pool occurs in a simple, downthrown anticline sealed by Winning Group shales. Geochemical analysis of oil extracted from core, suggests an earlier charge of 'Rough Range-type' oil, possibly generated from pre-Jurassic source rocks.Several prospects and a variety of play types are recognised and considerable exploration potential remains to be tested along the Rivoli-Bundegi Trend.

Petroleum exploration activity in Western Australia over the past decade has been on the increase, boosted by the positive results of many new discoveries, mainly on the North West Shelf but also in frontier areas. Significant discoveries in 1999–2000 resulted from new exploration concepts including deep plays in the Barrow/Dampier Sub-basins, heavy oil plays in the Carnarvon Basin, a deep-water gas play west of Gorgon, large gas/condensate plays in the Browse Basin, and a new gas play in the southern Bonaparte Basin. Discovery itself is a great incentive to the industry to further exploration; however, concerns over oil price, the Australian dollar, markets, policies and perceived prospectivity impact on exploration spending. The short-term outlook for WA is good as a result of existing work commitments including an average of 50 exploration wells to be drilled each year for the next three years. Onshore, where exploration has been subdued, there are signs of increased activity. The Western Australian government is playing a key role in promoting the State through gazettals, promotional activities— conferences and publications, acquiring precompetitive data and making petroleum data more accessible. The government funded Petroleum Exploration Initiatives program is continuing and efforts are being made to facilitate exploration. Sustained high oil prices, improvements in technology and efforts to expedite access to land are just some of the factors which will assist companies in their endeavours. In the longer term, continued growth in Western Australia’s petroleum industry is projected.

In late 2018, Esso Australia embarked on the drilling of Sculpin-1. Drilled in 2278 m of water, this is Australia’s deepest water exploration well and the first ultra-deep water well in the Gippsland Basin. Drilling of this well was the culmination of a bold exploration campaign in the VIC/P70 permit at the southeastern margin of the prolific hydrocarbon producing Gippsland Basin, which also saw the drilling of Baldfish-1 and Hairtail-1 in 2018. An east coast gas market with a high demand for additional gas resources combined with Esso Australia’s renewed technical focus on the deep and ultra-deep water sectors of the VIC/P70 exploration permit led to the identification of the Sculpin prospect, a stratigraphic lead premised on a late Cretaceous deep water reservoir system flowing into the south east Gippsland Basin depocentre from southern hinterlands. Technical analysis including integrated seismic toolkits, spectral decomposition and colour-blend imaging, rock properties and amplitude versus offset/direct hydrocarbon indicator modelling were key to Esso’s decision to test the new play with the Sculpin-1 well. Although the well did not encounter hydrocarbons, it did provide insights into reservoir quality, source and migration in the previously untested southeastern margin of the basin.

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.

It is possible to interpret many continental stresses on the Global Stress Map (Zoback, 1992) in terms of plate tectonics. Plate tectonics on a constant radius earth predicts a state of zero stress in Australia, except for northerly to northeasterly compression along the northern margin where Australia interacts with the Pacific Plate. However, the continent is everywhere in a state of significant horizontal compression, generally directed towards its centre.In southeastern Australia the current maximum horizontal compressional stress is directed northwestwards. While Gippsland Basin and Bass Basin developed under extensional stress from the Late Jurassic to Recent, there have been pulses of similarly directed compression in the Pliocene to Recent, Mid Miocene, Early Miocene, Late Eocene to Early Oligocene, Early Eocene, Paleocene, Campanian, Late Albian to Early Cenomanian, Aptian and Valanginian(?).Most of these pulses can also be demonstrated in such widely separated areas as the Carnarvon Basin in northwestern Australia, the Capricorn and Surat/Bowen Basins in eastern Australia, southern England, the Viking Graben in the North Sea and Pacific Guatemala. Pulses in the Portlandian, Callovian, Early Jurassic, Late Triassic and Mid Triassic appear to be similarly synchronous while two events in the Early Permian have been recognised also.Near-surface compressional pulses contemporaneous with lower crustal extension can be explained by continental flattening on an expanding earth. Such an interpretation is consistent with the centrewards horizontal compressional stresses observed in the Australian continent since at least the Late Triassic.Since an expansion pulse results in increased ocean basin capacity, compressional pulses have a strong tendency to coincide with the major sea level falls on the Haq et al (1987) global eustatic cycle chart.The orientations of horizontal compressional stresses appear to have varied little since the Late Triassic. If a basin axis is approximately perpendicular to those stresses the basin may record all compression pulses. However, repeated compression sub-parallel to a basin axis may induce movement on wrench faults which can be a threat to seal integrity.

Bush Blitz is an innovative and ambitious partnership between the Australian Biological Resources Study, BHP Billiton Sustainable Communities and the Earthwatch Institute (Australia) that aims to fill critical gaps in the knowledge of the biodiversity of Australia (http://www.bushblitz.org.au). Since its inception in 2009, over 900 putative new species of animals and plants have been discovered in Australian conservation reserves. As a unique approach to surveys in often-remote areas of the Australian outback, the Bush Blitz program has been highly successful and highlights the need for ongoing exploration and research to adequately document the biodiversity of Australia. This special issue of Australian Systematic Botany describes some of the newly discovered species and showcases the botanical results of the Bush Blitz program.

Oil and gas exploration in Australia, both on and offshore, has been centred on a small number of proven petroleum provinces and—given the extent of prospective basinal area that exists—it remains relatively under-explored to this day. Since the 1970s, companies have progressively spent a smaller proportion of their exploration budgets on onshore and shallow water targets, where discoveries have been regular yet unspectacular, in favour of the deeper waters, where higher risks are involved but the potential exists for significantly higher returns. This activity has led to the discovery of more than of 150 Tcf of gas in the North Carnarvon, Browse and Bonaparte basins, the majority of which sits in deepwater areas. An absence of infrastructure and a lack of an adequate market meant that these huge discoveries lay undeveloped; however, with developments in technology and demand for gas in Asia set to surge into the next decade, these previously stranded fields are set to move into development, underpinning economic growth in Australia and ensuring that the country moves to the forefront of the LNG industry worldwide. This paper will examine upstream activity, both on and offshore, in Australia since 2000, a decade in which the country has become one of the most prominent destinations for exploration expenditure in the world. Following the exploration cycle from acreage release through to discovery, it will look at how trends and activity have changed over time and examine how successful the industry has actually been. It will explore the factors driving activity and the effects external forces such as regulatory changes, oil price and prevailing economic conditions have had on activity levels. No post-Conference paper is available for this presentation. No post-conference paper is available for this presentation.

This paper presents the methodology that Conoco, a major international energy company, uses to make exploration investment decisions. This methodology includes a detailed and well coordinated analysis of the technical merits, cost environment, political/economic environment, and contract terms for every area of interest.Conoco continually monitors the activity in the more than 500 sedimentary basins around the world. A forecast of undiscovered reserves is made by country and basin. Obviously, all else being equal, it is better to search for oil in places considered to have the most oil left to be discovered. Gas prone areas tend to be of less interest.Once an area is identified to be of interest, data are collected on specific identifiable prospects to begin an exhaustive analysis. Recoverable reserves are estimated and the exploration program required to evaluate the area is determined.The development costs for the anticipated discovery are estimated along with production profiles. Sensitivity analyses are performed to view the effects of delays caused by factors beyond operator control.The political/economic environment in which operations would function is evaluated. A company must be able to anticipate that a government with stability and integrity will reign throughout the life of a project.Finally, the contract terms that govern the petroleum operations are analyzed. A complete discounted cash flow analysis is performed.This paper considers how each of these elements in the analysis might be a plus or a minus with regard to directing exploration funds toward Australia and shows that Australia affords an ideal mix of technical/geological merit with a workable acquisition environment and attractive economic reward. Comparisons will be made with other areas around the world.

The Moonie Field, located in the eastern portion of the Surat Basin and 300 km west of Brisbane, was discovered in December 1961 by Union Oil, operator of the 'UKA' joint venture consisting of Union Oil, Kern and AOG. Successful appraisal and development drilling led to the construction of the Moonie to Brisbane pipeline in 1963-64. Oil production commenced in 1964 and peaked in 1966 at a rate of 9000 BPD (1.4 ML/d). The oil is reservoired in the Precipice Sandstone and is trapped within the closure of the Moonie Anticline, located on the eastern and upthrown side of the Moonie-Goondiwindi Fault. Of the 38 wells drilled in the field to date, 32 have produced oil at economic rates. By August 1990, 22.23 MMBBL (3.5 GL) of oil had been produced from an estimated 59.1 MMBBL (9.3 GL) in place. Remaining recoverable reserves, with primary recovery, are estimated to be more than 1.5 MMBBL (0.2 GL). Enhanced oil recovery using both carbon dioxide and microbial techniques is currently being investigated by AGL Petroleum.The discovery of oil at Moonie represented the start of the commercial oil era in Australia. It provided encouragement for the petroleum exploration industry to expand the search and demonstrated that there were profits to be made from Australia's sedimentary basins. Moonie spawned a generation of petroleum exploration and production people who contributed to discoveries and developments elsewhere in Australia.

Abstract. A variety of paleogeographic reconstructions have been published, with applications ranging from paleoclimate, ocean circulation and faunal radiation models to resource exploration; yet their uncertainties remain difficult to assess as they are generally presented as low-resolution static maps. We present a methodology for ground-truthing the digital Palaeogeographic Atlas of Australia by linking the GPlates plate reconstruction tool to the global Paleobiology Database and a Phanerozoic plate motion model. We develop a spatio-temporal data mining workflow to validate the Phanerozoic Palaeogeographic Atlas of Australia with paleoenvironments derived from fossil data. While there is general agreement between fossil data and the paleogeographic model, the methodology highlights key inconsistencies. The Early Devonian paleogeographic model of southeastern Australia insufficiently describes the Emsian inundation that may be refined using biofacies distributions. Additionally, the paleogeographic model and fossil data can be used to strengthen numerical models, such as the dynamic topography and the associated inundation of eastern Australia during the Cretaceous. Although paleobiology data provide constraints only for paleoenvironments with high preservation potential of organisms, our approach enables the use of additional proxy data to generate improved paleogeographic reconstructions.

Sonadrill Lands Contract for Drillship Seadrill confirmed a new contract has been secured by Sonadrill Holding, Seadrill’s 50:50 joint venture with an affiliate of Sonangol for the drillship West Gemini. Sonadrill has secured a 10‑well contract with options for up to eight additional wells in Angola for an unknown operator. Total contract value for the firm portion of the deal is expected to be around $161 million, with further revenue potential from a performance bonus. The rig is expected to begin the work in the fourth quarter of this year with a firm term of about 18 months, in direct continuation of the West Gemini’s existing contract. The West Gemini is the third drillship to be bareboat chartered into Sonadrill, along with two Sonangol‑owned units, the Sonangol Quenguela and Sonangol Libongos. Seadrill will manage and operate the units on behalf of Sonadrill. Together, the three units position the Seadrill joint venture as an active rig operator in Angola, furthering the goal of building an ultradeepwater franchise in the Golden Triangle and driving efficiencies from rig clustering in the region. Petrobras Receives TotalEnergies, Shell Payments for Atapu TotalEnergies and Shell have formalized payments to Petrobras for separate, minority stakes in the pre‑salt Atapu field in the Santos Basin. TotalEnergies paid $4.7 billion reais ($940 million) while Shell paid closer to $1.1 billion. The Atapu block was acquired by the consortium comprising Petrobras (52.5%), Shell (25%), and TotalEnergies (22.5%) in the Second Bidding Round for the Transfer of Rights auction held 17 December 2021. The payments are compensation for monies spent thus far by Petrobras, which was granted contractual rights to produce 550 million BOE from Atapu in 2010. The partners will now work together to produce additional volumes from the field. Production at Atapu started in June 2020 via the P-70 FPSO. The unit is in about 2000 m of water and has the capacity to produce 150,000 BOED. CNOOC Brings New Bohai Sea Discoveries On Stream CNOOC Limited has kicked off production from its Luda 5‑2 oil field North Phase I project and Kenli 6‑1 oil field 4‑1 Block development project. Luda 5‑2 is in the Liaodong Bay of Bohai Sea, with average water depth of about 32 m and utilizes a thermal recovery wellhead platform and production platform tied into the Suizhong 36‑1 oil field. A total of 28 development wells are planned, including 26 production wells and two water‑source wells. The project is expected to reach its peak production of 8,200 B/D of oil in 2024. Kenli 6‑1 is in the south of Bohai Sea, with average water depth of about 17 m. The resource is being developed by a wellhead platform in addition to fully utilizing the existing processing facilities of the Bozhong 34‑9 oil field. A total of 12 development wells are planned, including seven production wells and five water‑injection wells. The field is expected to reach its peak production of 4,000 B/D of oil later this year. CNOOC Limited is operator and sole owner of the Luda 5‑2 oil field North and the Kenli 6‑1 oil field 4‑1 Block. Stabroek Block Bounty Off Guyana Gets Bigger The partners in the prolific Stabroek Block have again increased the gross discovered recoverable resource estimate for the area offshore Guyana. The owners now believe they have discovered reserves of at least 11 billion BOE, up from the previous estimate of more than 10 billion BOE. The updated resource estimate includes three new discoveries on the block at Barreleye, Lukanani, and Patwa in addition to the Fangtooth and Lau Lau discoveries announced earlier this year. The Barreleye‑1 well encountered approximately 70 m of hydrocarbon‑bearing sandstone reservoirs of which 16 m is high‑quality oil‑bearing. The well was drilled in 1170 m of water and is located 32 km southeast of the Liza field. The Lukanani‑1 well encountered 35 m of hydrocarbon‑bearing sandstone reservoirs of which approximately 23 m is high‑quality oil‑ bearing. The well was drilled in water depth of 1240 m and is in the southeastern part of the block, approximately 3 km west of the Pluma discovery. The Patwa‑1 well encountered 33 m of hydrocarbon‑bearing sandstone reservoirs. The well was drilled in 1925 m of water and is located approximately 5 km northwest of the Cataback‑1 discovery. “These new discoveries further demonstrate the extraordinary resource density of the Stabroek Block and will underpin our queue of future development opportunities,” said John Hess, chief executive of Hess and a partner in Stabroek. The co‑venturers have sanctioned four developments to date on Stabroek with both Liza and Liza Phase 2 on stream. The third planned development at Payara is ahead of schedule and is now expected to come on line in late 2023; it will utilize the Prosperity FPSO with a production capacity of 220,000 BOPD. The fourth development, Yellowtail, is expected to come on line in 2025, utilizing the ONE GUYANA FPSO with a production capacity of 250,000 BOPD of oil. At least six FPSOs with a production capacity of more than 1 million gross BOPD are expected to be on line on the Stabroek Block in 2027, with the potential for up to ten FPSOs to develop gross discovered recoverable resources. The Stabroek Block is 6.6 million acres. ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45% interest; Hess Guyana Exploration holds 30% interest; and CNOOC Petroleum Guyana Limited holds 25%. ConocoPhillips Gets Ekofisk License Extension Norway’s Ministry of Petroleum and Energy (MPE) has extended production licenses in the Greater Ekofisk Area from 2028 to 2048 with ConocoPhillips as operator. The company said the license extension provides long‑term operations and resource management aligned with the company’s long‑term perspective on the Norwegian continental shelf. Fields on the shelf are required to operate with a valid production license where the operator and licensees enter into an agreement with the authorities, including relevant field activities. The authorities may require commitments, leading to increased oil recovery. The existing production licenses 018, 018 B, and 275 in the Greater Ekofisk Area were set to expire on 31 December 2028; however, the MPE approved an extension through 2048. The new terms provide a potential for extending Ekofisk’s lifetime to nearly 80 years. The license partners are ConocoPhillips (operator, 35.11%), TotalEnergies EP Norge (39.896%), Vår Energi (12.388%), Equinor (7.604%), and Petoro (5%). BHP’s Wasabi Disappoints in US GOM Australian operator BHP encountered noncommercial hydrocarbons with its Wasabi‑2 well in the US Gulf of Mexico. BHP said the well in Green Canyon Block 124 was plugged and abandoned following the disappointing results. “This completes the Wasabi exploration program, with results under evaluation to determine next steps,” the company said. The well was targeting oil in an early Miocene reservoir. Transocean drillship Deepwater Invictus spudded the well in 764 m of water in November 2021. The previous Wasabi‑1 well had a mechanical problem and was plugged and abandoned 4 days earlier, prior to reaching its prospective targets. BHP operates Wasabi with a 75% interest. Lukoil Says Titonskaya Holds 150 Million BOE Russia’s Lukoil believes it has discovered around 150 million BOE following analysis of the two wells it drilled at the Titonskaya structure on the Caspian Sea shelf. Work is now underway to refine the seismic models of productive deposits and study deep samples of formation fluids. The results of the assessment will be submitted to the State Reserves Commission of the Russian Federation. The structure is in the central part of the Caspian Sea, not far from the Khazri field. Lukoil drilled the first well at the Titonskaya structure in 2020 and announced the new discovery in April 2021. According to that assessment, the probable geological resources of the Titonskaya are 130.4 million tons. In 2021, drilling of the second prospecting and appraisal well began to identify oil and gas deposits in the terrigenous‑carbonate deposits of the Jurassic‑ Cretaceous age. The well was drilled using the Neptune jackup drilling rig. The new find at Titonskaya will likely be tied into Khazri infrastructure. Petrobras’ Roncador IOR Project Comes On Line Petrobras has successfully started production from the first two wells of the improved oil recovery (IOR) project at the Roncador field in the Campos Basin offshore Brazil. The two wells are the first of a series of IOR wells to reach production. Startup is almost 5 months ahead of schedule and at half of the planned cost, according to partner Equinor. The wells will add a combined 20,000 BOED to Roncador, bringing daily production to around 150,000 bbl and reducing the carbon intensity (emissions per barrel produced) of the field. Through this first IOR project, the partnership will drill 18 wells that are expected to provide additional recoverable resources of 160 million bbl. Improvements in well design and the partners’ combined technological experience are the main drivers behind the 50% cost reduction across the first six wells, including the two in production. Roncador is Brazil’s fifth‑largest producing asset and has been in production since 1999. Petrobras operates the field and holds a 75% stake. In 2018, Equinor entered the project as a strategic partner with the remaining 25% interest. In addition to the planned 18 IOR wells, the partnership believes it can further improve recovery and aims to increase recoverable resources by a total of 1 billion BOE. The field has more than 10 billion BOE in place under a license lasting until 2052. The strategic alliance agreement also includes an energy‑efficiency and CO2‑emissions‑reduction program for Roncador. Gazania-1 To Spud Off South Africa Africa Energy will move ahead with its planned Gazania‑1 wildcat well offshore South Africa after securing partner Eco Atlantic’s $20 million in capital requirements for its portion of the probe. The well will be drilled in Block 2B. Island Drilling semisubmersible Island Innovator has been contracted for the work and is expected to mobilize from its current location in the North Sea for the 45‑day trip to South Africa. The Block 2B joint venture plans to spud the well by October with drilling expected to last 30 days, including a full set of logs if the well is successful. The block has significant contingent and prospective resources in relatively shallow water and contains the A‑J1 discovery that flowed light sweet crude oil to surface. Gazania‑1 will target two large prospects 7 km updip from A‑J1 in the same region as the recent Venus and Graff discoveries. Block 2B is located offshore South Africa in the Orange Basin where both TotalEnergies and Shell recently announced significant oil and gas discoveries offshore Namibia. The block covers 3062 km2 approximately 25 km off the west coast of South Africa near the border with Namibia in water depths ranging from 50 m to 200 m. The Southern Oil Exploration Corp. (Soekor) discovered and tested oil on Block 2B in 1988 with the A‑J1 borehole, which intersected thick reservoir sandstones between 2985 m and 3350 m. The well flowed 191 B/D of 36 °API oil from a 10‑m sandstone interval at around 3250 m. Africa Energy has a 27.5% interest in Block 2B offshore South Africa. The block is operated by a subsidiary of Eco Atlantic which holds a 50% interest. A subsidiary of Panoro Energy holds a 12.5% stake, and Crown Energy AB indirectly holds the remaining 10%. Brazil Grants New Exploration Blocks Brazil’s National Agency of Petroleum, Natural Gas, and Biofuels (ANP) has granted 59 exploratory blocks of oil and natural gas to 13 companies, including Shell, TotalEnergies, and 3R Petroleum. The awards were part of a permanent bid offer round held in Rio de Janiero in April. The auction totaled 422.4 million reais in signature bonuses with leases granted in six Brazilian states: Rio Grande do Norte, Alagoas, Bahia, Espírito Santo, Santa Catarina, and Paraná. The awards will result in investments of 406.3 million reais in the exploratory phase of the contracts. Shell Brazil (70%) was granted six blocks in the Santos Basin in a consortium with the Colombian Ecopetrol (30%). The blocks leases were SM‑1599, SM‑1601, SM‑1713, SM‑1817, SM‑1908, and SM‑1910. TotalEnergies won two areas in the same basin while Brazilian company 3R Petroleum received six areas in the Potiguar Basin. Petro‑Victory was also awarded 19 new blocks in Potiguar, increasing its holdings in Brazil to 38 blocks (37 in Potiguar). The new blocks are nearby Petro‑Victory infrastructure at the Andorinha, Alto Alegre, and Trapia oil fields. Eni Finds More Oil in Egypt’s Western Desert Eni struck new oil and gas reserves with a trio of discoveries in the Meleiha concessions of Egypt’s Western Desert. The finds have already been tied into existing infrastructure in the region and have added around 8,500 BOED to overall production from the area. The operator drilled the Nada E Deep 1X well, which encountered 60 m of net hydrocarbon pay in the Cretaceous‑Jurassic Alam El Bueib and Khatatba formations Meleiha SE Deep 1X well, which found 30 m of net hydrocarbon pay in the Cretaceous‑Jurassic sands of the Matruh Khatatba formations, and the Emry Deep 21 well, which encountered 35 m of net hydrocarbon pay in the massive cretaceous sandstones of Alam El Bueib. The results, added to the discoveries of 2021 for a total of eight exploration wells, give Eni a 75% success rate in the region. The company added that additional exploration activities in the concession are ongoing with “promising indications.” With these discoveries, Eni, through AGIBA, a joint venture between Eni and EGPC, continues to pursue its near‑field strategy in the mature basin of the Western Desert, aimed at maximizing production by containing development costs and minimizing time to market. Eni is planning a new high‑resolution 3D seismic survey in the Meleiha concession this year to investigate the gas potential of the area. Eni is currently the leading producer in Egypt with an equity production of around 360,000 BOED.

The Australian Government usually releases new offshore exploration acreage once a year. The proposed 2016 Release Areas are located across various offshore hydrocarbon provinces and include mature basins with ongoing oil and gas production as well as exploration frontiers. In support of the annual acreage release, Geoscience Australia provides a variety of geological information with an emphasis on basin evolution, stratigraphic frameworks, and overviews of hydrocarbon prospectivity. Geoscience Australia’s petroleum geological studies are aimed at the evolution of hydrocarbon-bearing basins at a regional scale, and include a review of source rock occurrences, their distribution and geochemical characters. Following the recent oil discovery in the Roebuck Basin, a strong focus of Geoscience Australia’s work is being placed on the Triassic period, and any new findings will directly underpin the release of new exploration acreage. Recent updates to stratigraphic frameworks and new results from geochemical studies are regularly published, and are used by Geoscience Australia for prospectivity assessments. Furthermore, the Australian Government continues to assist offshore exploration activities by providing ready access to a wealth of geological and geophysical data.

Abstract. A variety of paleogeographic atlases have been constructed, with applications from paleoclimate, ocean circulation and faunal radiation models to resource exploration; yet their uncertainties remain difficult to assess, as they are generally presented as low-resolution static maps. We present a methodology for ground-truthing paleogeographic maps, by linking the GPlates plate reconstruction tool to the global Paleobiology Database and a Phanerozoic plate motion model. We develop a spatio-temporal data mining workflow to compare a Phanerozoic Paleogeographic Atlas of Australia with biogeographic indicators. The agreement between fossil data and paleogeographic maps is quite good, but the methodology also highlights key inconsistencies. The Early Devonian paleogeography of southeastern Australia insufficiently describes the Emsian inundation that is supported by biogeography. Additionally, the Cretaceous inundation of eastern Australia retreats by 110 Ma according to the paleogeography, but the biogeography indicates that inundation prevailed until at least 100 Ma. Paleobiogeography can also be used to refine Gondwana breakup and the extent of pre-breakup Greater India can be inferred from the southward limit of inundation along western Australia. Although paleobiology data provide constraints only for paleoenvironments with high preservation potential of organisms, our approach enables the use of additional proxy data to generate improved paleogeographic reconstructions.

Australian exploration battled on through the challenging headwinds of 2020 and surprisingly, 2020 saw an increase in exploration drilling on 2019 activity. Twenty-five exploration wells were drilled in 2020 versus 20 exploration wells drilled in 2019. Eight discoveries were made during the year, with the most significant being the Enterprise discovery in the Otway Basin. 2020 also saw a return to exploration drilling in the Beetaloo Sub-basin unconventional plays. Appraisal drilling was dominated by Cooper-Eromanga Basin and coal seam gas activity. There were no offshore appraisal wells in 2020. The exploration farm-in deals of note were Santos taking additional equity from Armour in their South Nicholson Basin unconventional project and Origin taking additional equity from Falcon in their Beetaloo Sub-basin unconventional project. Origin also farmed into the Canning Basin position of Buru Energy and Rey Resources. Australia is set for an exciting year of exploration ahead with a return to exploration drilling in the Bedout Sub-basin, further exploration drilling in the North Perth Basin and a continuation of drilling and testing of the unconventional plays in the Beetaloo Sub-basin.

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

The exploration of the coast of Western Australia by English and French explorers in the late eighteenth and early nineteenth centuries led to the first recorded discoveries of fossiliferous rocks in Western Australia. The first forty years of exploration and discovery of fossil sites in the State was restricted entirely to the coast of the Continent. Following the establishment of permanent settlements in the 1820s the first of the inland fossil localities were located in the 1830s, north of Albany, and north of Perth. As new land was surveyed; particularly north of Perth, principally by the Gregory brothers in the 1840s and 1850s, Palaeozoic rocks were discovered in the Perth and Carnarvon Basins. F.T. Gregory in particular developed a keen interest in the geology of the State to such an extent that he was able, at a meeting of the Geological Society of London in 1861, to present not only a geological map of part of the State, but also a suite of fossils which showed the existence of Permian and Hesozoic strata. The entire history of nineteenth century palaeontology in Western Australia was one of discovery and collection of specimens. These were studied initially by overseas naturalists, but latterly, in the 1890s by Etheridge at The Australian Museum in Sydney. Sufficient specimens had been collected and described by the turn of the century that the basic outline of the Phanerozoic geology of the sedimentary basins was reasonably well known.

Relative to its needs over the last 30 years, Australia has enjoyed a high level of self-sufficiency. Whilst the overall remaining reserves of oil have been relatively constant, reserves of condensate have grown substantially as major reserves of natural gas have been added to Australia’s resource inventory. Oil and condensate reserves stand at 3.43 billion barrels (505 GL), of which 50% is condensate in gas fields. Australia’s undiscovered oil potential in its major offshore hydrocarbon producing basins has been upgraded to an indicative 5 billion barrels (800 GL) at the average expectation, following evaluation of the assessment results for Australia in the authoritative worldwide assessment of undiscovered potential by the US Geological Survey.Current reserves, however, are insufficient to sustain present levels of production in the medium term. Estimates of future production of oil and condensate suggest that at the mean expectation, production rates will drop by around 33% by 2005 and 50% by 2010, largely as a result of a decline in oil production. This forecast includes production from fields that have not yet been discovered. Condensate production will continue to grow, but the rate of growth is constrained by gas production rates and overall by the development timetable for the major gas fields.The rate of discovery of new oil fields is insufficient to replace the oil reserves that are being produced. If Australia is to maximise the opportunity to maintain production at similar levels to the recent past, it is probable that exploration effort will have to diversify to the frontier basins to locate a new oil province whilst continuing to explore the full potential of the known hydrocarbon-bearing basins. Australia still has a remarkable number of basins which have received little or no exploration. Whilst there is no substitute for a discovery to stimulate exploration in poorly known areas, demonstrating that petroleum has been generated and migrated is the key to attracting continued exploration interest.

Since the early 2000s, southeastern Senegal has emerged as a premier gold exploration and mining frontier. At present, the Sabodala gold mine, owned by the Canadian company Teranga Gold, is the only operational gold mine and mill in Senegal. But two more open-pit gold operations are scheduled to open this year, and several other companies have announced discoveries of industrial-scale deposits. By documenting the shifting ownership and exploration of the Sabodala deposit, this article draws attention to how the protracted phase of mineral research shapes the political life of mining operations in Africa and elsewhere in the global South. Geological exploration in colonial and post-colonial Senegal, as in much of Africa, has relied heavily on the expertise of indigenous miners and smelters. Mining Sabodala has thus unearthed multi-vocal and contested histories of gold discovery. Historians of science have established that field assistants and experts in Africa have produced agronomic and medical knowledge typically credited to “the West.” By extending this argument to gold exploration, the article brings African history into dialogue with an emergent anthropology of subterranean knowledge production.

The Polda Basin is an intracratonic basin, at least 5000 m in depth, extending from the edge of the Great Australian Bight nearly 400 km east to the centre of Eyre Peninsula in southern South Australia, it can now be recognised as a structural feature of some antiquity, originating possibly as a crustal downwarp in Proterozoic time during the same orogenic regime that gave rise to the Officer and Amadeus basins of central Australia, with which it has strong affinities. Its internal structure indicates that it has been subject to the same orogenic episodes that have affected southern and central Australia, culminating in rotational block faulting associated with the final pull-apart of Gondwanaland. Extensive salt mobilisation observed on seismic sections, confirmed by the drilling of the Mercury 1 and Columbia 1 wells, supports the concept of the basin's Cambrian or Precam-brian origins.The exploration history of the basin is a useful example of the application of a number of geophysical disciplines to arrive at a satisfactory interpretation. A reappraisal of geophysical data was undertaken after Outback Oil N.L. drillhole Gemini 1 penetrated 'uneconomic' basement at 856 m, far short of the anticipated sedimentary section of 1830-2440 m. Interpretation of shipborne magnetic data, not previously considered, indicated that a seismic horizon close to where Gemini 1 penetrated igneous rock was related to a thin layer of magnetic material which did not correspond to deep magnetic basement. Further detailed aeromagnetic and seismic studies confirmed this interpretation, which was tested by the drilling of two exploration wells. Mercury 1 and Columbia 1. Although unsuccessful as hydrocarbon discovery wells, these two wells confirmed the overall validity of the interpretation. Stratigraphic information derived from these wells and from further geophysical studies and drilling onshore have led to a new assessment of the basin and its potential.

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.

Deepwater sampling in New Zealand and southern Australian waters over the past two decades has significantly improved knowledge of all invertebrate groups, including decapod crustaceans. Thorid shrimps of the genus, Paralebbeus Bruce & Chace, 1986 are associated with deepwater hexactinellid sponges, with four species known to date from scattered localities in the southwestern Indian Ocean, northwestern Australia, Southeast Asia and the northwestern Pacific including Japan. Paralebbeus pegasus sp. nov. is described from New Zealand and southeastern Australia, representing the first record of the genus from the temperate southwestern Pacific. The new species of Paralebbeus is unique in the genus for having meral spines on pereopods 3–5. A key to the species of Paralebbeus and global distribution map are provided.

ABSTRACT Research is underway to develop a range of methods for assessing and managing exploration risk, progress, and value. As part of the research, a collaborative project was undertaken by SRK Consulting, working with Placer Granny Smith (the operating company of the Granny Smith Joint Venture owned by Placer Dome Asia Pacific, 60%, and Delta Gold, 40%) and Placer Dome Asia Pacific, to review and quantify exploration success in a mature program that has delivered several mines. In particular, an objective was to develop a measurement technique that is more commercially robust and informative than the traditional “cost per resource ounce discovered” method. The project reviewed gold exploration over the past 13 years in the Laverton district of Western Australia. Placer Granny Smith has spent AUD$52 million (about US$30 million at recent exchange rates) defining 12 deposits with combined resources of more than 10 Moz (310 tonnes) of gold. Exploration centered on the Archean Granny Smith gold deposit, and was primarily targeted at outlining additional resources to feed through the Granny Smith mill. At an overall cost per resource ounce of less than US$3, this has clearly been a successful program. However, our analysis demonstrates that this figure fails to provide a complete value picture, and that the program could have delivered even greater value to the participating companies. While the quantitative results of the review are specific to the Laverton district, the methodology can be applied to near-mine, advanced, and grassroots exploration programs for any deposit style in any geologic environment. Key outcomes of the review are as follows: Measuring exploration success in terms of the net present value of the deposit outlined produces a markedly different and arguably more commercially realistic outcome than measuring it in relation to the average cost of resources defined.Early recognition and prompt drill testing of key targets is critical in optimizing opportunities and realizing exploration value. Indeed, the principal destroyer of value in exploration is spending too much time and money prior to drill testing the best targets in any area.Continual and robust ranking of exploration targets should be undertaken. Exploration should aim to rapidly identify and systematically test the best exploration targets, rather than systematically exploring the project areas. Especially in the current climate of a depressed resources sector, the exploration industry needs to compete aggressively for the investor’s dollar. The industry needs more robust and quantitative methodologies for measuring exploration effectiveness, and for informing management, investors, and shareholders of exploration risk, reward, value, and progress to discovery. The probabilistic methods described below provide such a framework.

Amplitude versus offset (AVO) technology has proved itself useful in petroleum exploration in various parts of the world, particularly for gas exploration. To determine if modern AVO compliant processing could identify potential anomalies for exploration of open acreage offshore Australia, Geoscience Australia reprocessed parts of four publicly available long cable lines. These lines cover two 2006 acreage release areas on the Exmouth Plateau and in the Browse Basin on the North West Shelf. An earlier study has also been done on two publicly available long cable lines from Geoscience Australia’s Bremer Basin study and cover areas from the 2005 frontier acreage release on the southern margin. The preliminary results from these three reprocessing efforts produced AVO anomalies and were made publicly available to assist companies interested in assessing the acreage. The results of the studies and associated data are available from Geoscience Australia at the cost of transfer.The AVO data from the Exmouth Plateau show AVO anomalies including one that appears to be at the Jurassic level of the reservoir in the Jansz/Io supergiant gas field in adjacent acreage to the north. The AVO data from the Caswell Sub-basin of the Browse Basin show an AVO anomaly at or near the stratigraphic zone of the Brecknock South–1 gas discovery to the north. The geological settings of strata possibly relating to two AVO anomalies in the undrilled Bremer Basin are in the Early Cretaceous section, where lacustrine sandstones are known to occur. The AVO anomalies from the three studies are kilometres in length along the seismic lines.These preliminary results from Geoscience Australiaand other AVO work that has been carried out by industry show promise that AVO compliant processing has value—particularly for gas exploration offshore Australia—and that publicly available long-cable data can be suitable for AVO analysis.

The northern Perth Basin is an area where recent seismic advances combined with new geological insight, have led to exploration success with a significant new gas field discovery at Beharra Springs and a number of other minor discoveries. This paper outlines 'new concepts' with regard to stratigraphy and structure and how this has been balanced with the commercial environment to rejuvenate exploration in the northern Perth Basin. The Perth Basin is unique in Australia, as running through the middle of the Basin is the West Australian Natural Gas (WANG) pipeline which will be operating at approximately 26 per cent of its capacity in 1992. With the deregulation of the natural gas market in 1988, supply of gas to the Western Australian market via the State Energy Commission of Western Australia (SECWA) pipeline from the Carnarvon Basin, and in particular, the North West Shelf project, can now be balanced with supply from the onshore Perth Basin carried by the WANG pipeline.The minimum economically viable gas field in the northern Perth Basin is calculated to be 15 BCF (16.05 PJ) and the expected median field size is 50 BCF (53.5 PJ) of recoverable gas. Based on the historical success rate of one in eight, typical finding costs are 12 c/MCF (12 c/GJ).In the 1990/91 financial year, eight onshore exploration wells were drilled in Western Australia of which five were drilled in the northern Perth Basin. Provided the market access and opportunities remain, it is anticipated that the recent technological developments will sustain exploration and development of the onshore northern Perth Basin.

The excavation report covers eight months of fieldwork at the site of Ghazali, which resulted in the clearing of the entire monastery and the discovery of three annexes located on the north and west of the complex. The spiritual part of the monastery included two churches located in the southeastern corner of the complex, a household compound on the west side and a refectory and dormitory in between. Conservation work focused on the reconstruction and restoration of water storage installations in Room Y, as well as north of the North Church. Excavation outside the monastic walls brought the discovery of an iron smelting area with several well-preserved furnaces. Exploration of the monks’cemetery uncovered regular box superstructures and an intriguing variety of substructures from simple vertical pit tombs to elaborate vaulted chambers.

Australia has abundant natural gas reserves and is presently the world's fourth largest exporter of LNG. New projects and strengthening demand, led by rising energy consumption in China and India, is expected to increase Australia’s ranking to second by 2015. The discovery of new petroleum reserves also has the potential to reduce Australian energy import dependence and increase supply certainty.With sustainable development and energy security in mind, the Department of Resources, Energy and Tourism is leading the development of the Government’s resources policy to facilitate investment in Australia’s upstream petroleum industry.The 2011 Australian Offshore Petroleum Exploration Acreage Release offers the global petroleum exploration industry a variety of investment opportunities. Release areas are located across nine basins, vary in size and level of existing geological knowledge, are located in a range of water depths, and are supported by pre-competitive and open-file geological and geophysical data.The Acreage Release is underpinned by a stable economic environment and well established regulatory framework, which seeks to balance environmental, social and economic considerations during the development of Australia’s natural resources.The detailed Acreage Release information package is available at online at www.petroleum-acreage.gov.au or by visiting the Commonwealth Government’s booth at the APPEA conference.

Abstract. The International Ocean Discovery Program (IODP) conducted a series of expeditions between 2013 and 2016 that were designed to address the development of monsoon climate systems in Asia and Australia. Significant progress was made in recovering Neogene sections spanning the region from the Arabian Sea to the Sea of Japan and southward to western Australia. High recovery by advanced piston corer (APC) has provided a host of semi-continuous sections that have been used to examine monsoonal evolution. Use of the half-length APC was successful in sampling sand-rich sediment in Indian Ocean submarine fans. The records show that humidity and seasonality developed diachronously across the region, although most regions show drying since the middle Miocene and especially since ∼ 4 Ma, likely linked to global cooling. A transition from C3 to C4 vegetation often accompanied the drying but may be more linked to global cooling. Western Australia and possibly southern China diverge from the general trend in becoming wetter during the late Miocene, with the Australian monsoon being more affected by the Indonesian Throughflow, while the Asian monsoon is tied more to the rising Himalaya in South Asia and to the Tibetan Plateau in East Asia. The monsoon shows sensitivity to orbital forcing, with many regions having a weaker summer monsoon during times of northern hemispheric Glaciation. Stronger monsoons are associated with faster continental erosion but not weathering intensity, which either shows no trend or a decreasing strength since the middle Miocene in Asia. Marine productivity proxies and terrestrial chemical weathering, erosion, and vegetation proxies are often seen to diverge. Future work on the almost unknown Paleogene is needed, as well as the potential of carbonate platforms as archives of paleoceanographic conditions.

Australia is a nation rich in natural gas resources.Natural gas markets, historically, have been developed following a major discovery nearby. Natural gas is now firmly entrenched as a major primary fuel in a competitive and dynamic market.Marketing theory indicates that sales of a product can be broken into three phases: introduction-growth, maturity, and decline.The Australian natural gas markets are presently entering the mature phase. To sustain the economic incentive for further exploration, natural gas explorers and producers need to become more aware of the market environment in which they compete. Development of new markets and technology today will ensure the need for gas exploration in the future.