Journal articles on the topic 'Seismic prospecting Australia'

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

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.

Regional geophysics research provides for prospect assessment of Timor-Leste, part of the Southeast Asia Archipelago in a region embracing the Banda Arc, Timor Island, and the northwest Australia Gondwana continental margin edge. Timor Island is a microcontinent with several distinct tectonic provinces that developed initially by rifting and drifting away from the Australian Plate. A compressive convergence began in the Miocene whereby the continental edge of the large craton collided with the microcontinent, forming a subduction zone under the island. The bulk of Timor Island consists of a complex mélange of Tertiary, Cretaceous, Jurassic, Triassic, Permian, and volcanic features over a basal Gondwana craton. Toward the north, the offshore consists of a Tertiary minibasin facing the Banda Arc Archipelago, with volcanics interspersed onshore with the basal Gondwana pre-Permian. A prominent central overthrust nappe of Jurassic and younger layers makes up the mountains of Timor-Leste, terminating south against an accretionary wedge formed by this ongoing collision of Timor and Australia. The northern coast of the island is part of the Indonesian back arc, whereas the southern littoral onshore plus shallow waters are part of the accretionary prism. Deepwater provinces embrace the Timor Trough and the slope of the Australian continental margin being the most prospective region of Timor-Leste. Overall crust and mantle tectonic structuring of Timor-Leste is interpreted from seismic and potential field data, focusing mostly on its southern offshore geology where hydrocarbon prospectivity has been established with interpretation of regional seismic data and analyses of gravity, magnetic, and earthquake data. Well data tied to seismic provides focal points for stratigraphic correlation. Although all the known producing hydrocarbon reservoirs of the offshore are Jurassic sands, interpretation of Permian and Triassic stratigraphy provides knowledge for future prospect drilling risk assessment, both onshore and offshore.

The deep water portion of the Great Australian Bight remains an untested basin with the Gnarlyknots–1A well drilled in 2003 not penetrating deep enough to test the well's targets within the Upper Cretaceous Ceduna Delta section. If an anoxic marine shale source system, that is an effective source in many parts of West Africa, is present beneath the delta, then this could supply a material oil charge into the numerous fault block structures identified on seismic data. With eight wells due to be drilled in the next few years, this area will be one of the most active exploration frontier settings in the region. Since Australia has an open file system for technical data, the regional Flinders 2000 2D Marine seismic Interpretation report containing five regional Time structure maps is now in the public domain, as is the Gnarlyknots–1A well data and the raw seismic data from the Ceduna 3D survey acquired in 2012. These data were used to evaluate the untested Coniacian play interval with the construction of Reservoir Presence and quality, seal and charge relative probability maps made from various proxies that were then stacked to show areas of relative prospectivity. This traditional approach was supplemented by the an example showing pre-interpretation surfaces from the pre-Cenomanian portion of the 3D volume to help develop a better understanding of the potential prospectivity of deeper intervals not captured on the submitted open file maps. The workflow presented here suggests some parts of the Ceduna Sub Basin are significantly more prospective than others. Moreover, we demonstrate that even in frontier settings with minimal well data, pre-interpretation processing and simple play analysis together can be a useful and efficient approach for delivering significant insights into prospectivity. This workflow will ultimately promote more exploration thinking and activity in the future.

The increasing availability of 3D seismic data from sedimentary basins at volcanic and non-volcanic continental margins has provided fundamental new insights into both the storage and transport of magma in the continental crust. As global hydrocarbon exploration increasingly focuses on passive margin basins with evidence for past intrusive and extrusive igneous activity, constraining the distribution, timing and pathways of magmatism in these basins is essential to reduce exploration risk. Producing and prospective Australian passive margin basins where igneous systems have been identified include the Bight, Otway, Bass, Gippsland and Sorell basins of the southern margin. This paper reviews both the impacts of volcanic activity on sedimentary basin hydrocarbon prospectivity (e.g. advective heating, reservoir compartmentalisation and diagenesis), and the styles, distribution and timing of late Cretaceous–Recent extrusive and intrusive igneous activity along basins of the southern Australian margin, providing illustrative examples based on 2D and 3D seismic reflection data.

We constrain the depth and seismic structure of stiff sediment cover overlying a prospective basement terrane using a passive seismic technique which uses surface wave energy from microtremor (also known as ambient seismic energy or seismic noise). This may be applied to mineral exploration under cover to decrease the inherent ambiguity in modeling potential field data for exploration targeting. We use data from arrays of portable broadband seismometers, processed using both the multimode spatially averaged coherency (MMSPAC) method and the horizontal to vertical spectral ratio (HVSR) method, to produce profiles of seismic velocity structure along a 12-km transect. We have developed field protocols to ensure consistent acquisition of high-quality data in near-mine and remote locations and a variety of ground conditions. A wavefield approaching the theoretical ideal for MMSPAC processing is created by combining the energy content of an off-road vehicle, driven around the seismometer array, and ambient sources. We found that this combination results in significantly higher-quality MMSPAC waveforms in comparison with that obtained using ambient energy alone. Under ideal conditions, a theoretical maximum depth of investigation of 600 m can be achieved with a hexagonal sensor array with 50-m radius and MMSPAC and HVSR. The modeling procedure we employ is sensitive to layer thicknesses of [Formula: see text]. A high-velocity layer in the sediment package reduces the sensitivity to deeper structure. This can limit the modeling of underlying layers but may be addressed by detailed analysis of the HVSR peaks. Microtremor recordings including off-road vehicle noise, combined with the MMSPAC and HVSR processing techniques, may therefore be used to constrain sediment structure and depth to basement in a cost-effective and efficient method that could contribute greatly to future mineral exploration under cover.

Prior to the onshore work of Empire Energy Corporation International (Empire) it was widely believed that the widespread sheets (>650 m thick) of Jurassic dolerite (diabase) would not only have destroyed the many potential petroleum source and reservoir rocks in the basin but would also absorb seismic energy and would be impossible to drill. By using innovative acquisition parameters, however, major and minor structures and formations can be identified on the 1,149 km of 2D Vibroseis. Four Vibroseis trucks were used with a frequency range of 6–140 Hz with full frequency sweeps close together, thereby achieving maximum input and return signal. Potential reservoir and source rocks may be seismically mapped within the Gondwanan Petroleum System (GPS) of the Carboniferous to Triassic Parmeener Supergroup in the Tasmania Basin. Evidence for a working GPS is from a seep of migrated, Tasmanite-sourced, heavy crude oil in fractured dolerite and an oil-bearing breached reservoir in Permian siliciclastics. Empire’s wells show that each dolerite sheet consists of several intrusive units and that contact metamorphism is usually restricted to within 70 m of the sheets’ lower margins. In places, there are two thick sheets, as on Bruny Island. One near-continuous 6,500 km2 sheet is mapped seismically across central Tasmania and is expected, along with widespread Permian mudstones, to have acted as an excellent regional seal. The highly irregular pre-Parmeener unconformity can be mapped across Tasmania and large anticlines (Bellevue and Thunderbolt prospects and Derwent Bridge Anticline) and probable reefs can be seismically mapped beneath this unconformity within the Ordovician Larapintine Petroleum System. Two independent calculations of mean undiscovered potential (or prospective) resources in structures defined so far by Empire’s seismic surveys are 596.9 MMBOE (millions of barrels of oil equivalent) and 668.8 MMBOE.

Cultus Petroleum N.L. began exploration in petroleum permit EPP 23 of the offshore Otway Basin in December 1987. The permit was sparsely explored, containing only 2 wells and poor quality seismic data. A regional study was made taking into account the shape of the basin and the characteristics of the major seismic sequences. A prospective trend was recognised, running roughly parallel to the present shelf edge of South Australia. A new seismic survey was orientated over this prospective trend. The parameters were designed to investigate the structural control of the prospects in the basin. To improve productivity during the survey, north-south lines had to be repositioned due to excessive swell noise on the cable. The new line locations were kept in accordance with the structural model. Field displays of the raw 240 channel data gave encouraging results. Processing results showed this survey to be the best quality in the area. An FK filter was designed on the full 240 channel records. Prior to wavelet processing, an instrument dephase was used to remove any influence of the recording system on the phase of the data. Close liaison was kept with the processing centre over the selection of stacking velocities and their relevance to the geological model. DMO was found to greatly improve the resolution of steeply dipping events and is now considered to be part of the standard processing sequence for Otway Basin data. Seismic data of a high enough quality for structural and stratigraphic interpretation can be obtained from this basin.

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

There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.

The Amadeus and Ngalia Basins are two of several intracratonic basins situated in the central region of the Australian Continent and underlain by Upper Proterozoic and Lower Palaeozoic sedimentary rocks.In the Amadeus Basin, the preserved sedimentary section has been deformed by several orogenic events through geological history, with salt tectonics playing an important role in the structural evolution. The Ordovician System is the primary exploration objective. The Cambrian and Proterozoic sequences, which also carry rock strata having source, reservoir and sealing properties, are secondary targets. However, these latter units are sparsely explored, and only limited information is available on their petroleum prospectiveness. Three of the four petroleum accumulations found to date are in Ordovician sandstones, with the fourth accumulation contained in Cambrian sandstones.The initial drilling phase in the Amadeus Basin in the early 1960s was concentrated on geologically defined surface antic :nes, with seismic surveying becoming the principal technique employed in subsequent exploration phases. The ongoing work has demonstrated a major untested structural play associated with a regional thrust fault system — in particular, combination dip and fault closures developed on the underthrust blocks. Stratigraphic prospects also are present in the Amadeus Basin, but none of these yet has been drilled.The Ngalia Basin is similar stratigraphically and structurally to the Amadeus Basin and is considered prospective for oil and gas. Much less work has been done in the Ngalia than in the Amadeus, with only one well drilled in the entire basin. The well yielded a gas snow from a Proterozoic formation, and other direct hydrocarbon indications have been recorded elsewhere in the basin. Rock units having source, reservoir and sealing parameters are present, as are structures capable of forming traps. Again, these are associated largely with a complex regional thrust fault system.

The Georgina Basin is an intracratonic basin on the central-northern Australian craton. Its southern portion includes a highly prospective Middle Cambrian petroleum system which remains largely unexplored. A plethora of stratigraphic names plagued previous exploration but the lithostratigraphy has now been rationalised using previously unpublished electric-log correlations and seismic and core data.Neoproterozoic and Lower Palaeozoic sedimentary rocks of the southern portion of the basin cover an area of 100,000 km2 and thicken into two main depocentres, the Toko and Dulcie Synclines. In and between these depocentres, a Middle Cambrian carbonate succession comprising Thorntonia Limestone and Arthur Creek Formation provides a prospective reservoir-source/seal couplet extending over 80,000 km2. The lower Arthur Creek Formation includes world class microbial source rocks recording total organic carbon (TOC) values of up to 16% and hydrocarbon yields up to 50 kg/tonne. This blanket source/seal unconformably overlies sheetlike, platform dolostone of the Thorntonia Limestone which provides the prime target reservoir. Intra- Arthur Creek high-permeability grainstone shoals are important secondary targets.In the Toko Syncline, Middle Cambrian source rocks entered the oil window during the Ordovician, corresponding to major sediment loading at this time. The gas window was reached prior to structuring associated with the Middle Devonian-Early Carboniferous Alice Springs Orogeny, and source rocks today lie in the dry gas window. In contrast, high-temperature basement granites have resulted in overmaturity of the Arthur Creek Formation in the Dulcie Syncline area. On platform areas adjacent to both these depocentres source rocks reached peak oil generation shortly after the Alice Springs Orogeny; numerous structural leads have been identified in these areas. In addition, an important stratigraphic play occurs in the Late Cambrian Arrinthrunga Formation (Hagen Member) on the southwestern margin of the basin. Key elements of the play are the pinchout of porous oil-stained, vuggy dolostone onto basement where top seal is provided by massive anhydrite while underlying Arthur Creek Formation shale provides a potential source.

This study assesses potential geological connections between the unconventional petroleum plays in the Beetaloo Sub-basin, regional aquifers in overlying basins, and the near surface water assets in the Beetaloo Sub-basin Northern Territory, Australia. To do so, we built an innovative multi-disciplinary toolbox including multi-physics and multi-depth imaging of the geological formations, as well as the study of potentially active tectonic surface features, which we combined with measurement of the helium content in water sampled in the aquifer systems and a comparative analysis of the surface drainage network and fault lineaments orientation. Structures, as well as potential natural active and paleo-fluid or gas leakage pathways, were imaged with a reprocessing and interpretation of existing and newly acquired Beetaloo seismic reflection 2D profiles and magnetic datasets to determine potential connections and paleo-leakages. North to north-northwest trending strike slip faults, which have been reactivated in recent geological history, are controlling the deposition at the edges of the Beetaloo Sub-basin. There are two spring complexes associated with this system, the Hot Spring Valley at the northern edge of the eastern Beetaloo Sub-basin and the Mataranka Springs 10 km north of the western sub-basin. Significant rectangular stream diversions in the Hot Spring Valley also indicates current or recently active tectonics. This suggests that those deep-rooted fault systems are likely to locally connect the shallow unconfined aquifer with a deeper gas or fluid source component, possibly without connection with the Beetaloo unconventional prospective plays. However, the origin and flux of this deeper source is unknown and needs to be further investigated to assess if deep circulation is happening through the identified stratigraphic connections. Few north-west trending post-Cambrian fault segments have been interpreted in prospective zones for dry gas plays of the Velkerri Formation. The segments located in the northern part of the eastern Beetaloo Sub-basin do not show any evidence of modern leakages. The segments located around Elliot, in the south of the eastern Beetaloo Sub-basin, as well as low-quality seismic imaging of potential faults in the central part of the western sub-basin, could have been recently reactivated. They could act as open pathways of fluid and gas leakage, sourced from the unconventional plays, deeper formations of the Beetaloo Sub-basin or even much deeper origin, excluding the mantle on the basis of low 3He/4He ratios. In those areas, the data are sparse and of poor quality; further field work is necessary to assess whether such pathways are currently active.

The discoveries of the Katnook Field and, later, the Ladbroke Grove Field were significant milestones for hydrocarbon exploration in the southeast of South Australia as well as for the Otway Basin in general. The initial 1987 discovery at Katnook-1 of a relatively shallow gas accumulation in the basal part of the Eumeralla Formation was eclipsed in late 1988 at the Katnook-2 appraisal stage where deeper and more significant gas reserves were discovered in the Pretty Hill Sandstone.Technological improvement, in seismic acquisition, in particular, use of longer offset configurations and higher fold, and in filtering and correction techniques at the processing stage, are discussed in relation to improved geologic understanding. These aspects ultimately led to drilling success in both exploration and appraisal.At the deep Katnook discovery stage several significant problem areas remained unresolved. These related to uncertainties in vertical distribution of gas pay, level of a gas-water contact, and unreliable reserve estimates the result of the inability of conventional log analysis techniques to distinguish gas-bearing from water-bearing sands. Both in the evaluation of Katnook-2 and at the Katnook-3 appraisal stage, expensive cased-hole testing programs were undertaken to determine the size, extent and producibility of the gas accumulation. A key development between drilling Katnook-2 and Katnook-3 was the discovery of carbon dioxide-rich gas at Ladbroke Grove during 1989 in an adjacent structure to the south.The Katnook Field was the first commercial gas field development in the southeast, South Australian part of the Otway Basin, with gas sales commencing in March 1991, within a year of completing field appraisal. The discoveries, and subsequent development, have led to a renewed focus on the Otway Basin as a prospective hydrocarbon province.

The Perth Basin may have been regarded in the past as prospectively poor, but things are about to change! Seismic quality was generally poor, reservoirs often tight and source- rock maturity data limited. Abundant source rocks which tend to have a predominance of Type III kerogens have been identified and the basin has often been referred to as gas prone, the two largest discoveries having combined recoverable reserves greater than 444 billion cubic feet (12.5 Gm3).Advances in seismic acquisition and processing, available from the early 1980s, is drawing back the veil that has enveloped major areas of the basin for many years. An estimated 29 wells out of 40 exploration wells studied in the northern area of the Perth Basin were drilled off- structure. Established plays are now being correctly delineated and oil- prone source rocks with good generative potential have been identified.Perhaps the most significant occurrence in the Perth Basin was the discovery of a new play in 1987 which stimulated a new round of activity. This will undoubtedly provide economic discoveries for the participants. This renewed prospectivity will spill over into the offshore areas in the near future.The northern area of the Perth Basin has an historic exploration risk of 12.5 per cent. With future exploration risk predicted at 20- 30 per cent, this area will become one of the most prospective onshore basins in Australia.

The Torres Basin is a recently discovered Mesozoic basin in the Papuan Plateau, southeast Papua New Guinea. Newly acquired deepwater offshore seismic data and older regional data have been (re)interpreted with the view of defining structural regimes in line with the onshore geological maps and conceptual cross sections. A regional time-space plot has been developed to elucidate the breakup of the northeastern Australian Plate with a focus on the geological history of the Papuan Plateau, which holds the Torres Basin geological section. This in turn has led to a re-evaluation of the structural style and history of the southern coastal region incorporating the East Australian Early Cretaceous Island Arc; it highlights that a significant horizontal structural grain needs to be considered when evaluating the petroleum potential of the region. The southern margin is characterised as a frontal thrust system, similar to the nearby Papuan Basin. A series of regional strike lines in conjunction with the dip lines is used to divide the region into prospective and non-prospective exploration play fairways. The role of transfer faults, basement-detachments faults, regional-scale thrust faults, and recent normal faulting is discussed in the compartmentalisation of the geological section. There is basement-involved anticlinal development on a large scale and a complementary smaller-scale thin-skinned anticlinal trend. These trends are characterised as having significant strike length and breadth. Anticlinal trap fairways have been defined and have similar size and distribution as that of the Papuan Basin.

The Officer Basin described in this paper includes four Proterozoic to Lower Palaeozoic sub-basins (Gibson, Yowalga, Lennis, Waigen) which extend in a northwest to southeast belt across 200 000 sq. km of central Western Australia. These sub-basins are bounded by Archaean to Proterozoic basement blocks and are almost entirely concealed by a veneer of Permian and Cretaceous sediments. Depth to magnetic basement locally exceeds eight kilometres.Until recently, information on the sub-surface geology was limited to shallow levels, based on the results of a petroleum exploration campaign in the 1960s and the work of State and Federal Geological Surveys. In 1980, the Shell Company of Australia was awarded three permits (46 200 sq. km) covering the Yowalga and Lennis Sub-basins. The results of 4700 km of seismic data and three deep wildcat wells, combined with gravity, aeromagnetic, Landsat, outcrop and corehole information, has led to a better understanding of the regional subsurface geology.The Lennis Sub-basin appears to contain Lower to Middle Proterozoic sediments, whereas the Yowalga Sub- basin is primarily an Upper Proterozoic to Lower Cambrian sequence which comprises a basal clastic section, a middle carbonate and evaporite sequence and an upper clastic section. Widespread Middle Cambrian basalts cap the Upper Proterozoic to Lower Cambrian prospective sequence. Late Proterozoic uplift resulted in salt- assisted gravity tectonics leading to complex structural styles, especially in the basin axis.Despite oil shows, organic matter in the oil and gas generation windows and reservoir-quality sandstones with interbedded shales, no convincing source rocks or hydrocarbon accumulations have yet been located. The area remains, however, one of the least explored basins in Australia.

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2,500 km of seismic data occur over a prospective area of 73,000 km2 which comprises three stacked sedimentary basins of Palaeozoic to Mesozoic age. In this area three petroleum systems have potential related to important source intervals in the Early Jurassic Eromanga Basin (Poolowanna Formation), the Triassic Simpson Basin (Peera Peera Formation) and Early Permian Pedirka Basin (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. Basin modelling using modern techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time, when source rocks entered the wet gas maturation window.The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone equivalent, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/Tirrawarra petroleum system found in the Cooper Basin.An integrated investigation into the hydrocarbon charge and migration history of Colson–1 was carried out using CSIRO Petroleum’s OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the Early Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone equivalent. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin.Conventional structural targets are numerous, but the timing of hydrocarbon expulsion dictates that those with an older drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source kitchens on relatively short migration pathways. Early formed stratigraphic traps at the level of the Tirrawarra Sandstone equivalent and Poolowanna Formation are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir–seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.

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

The Bight Basin, on Australia’s southern margin, is one of the world's most prospective deepwater frontier basins. The 10 offshore wells drilled in the basin had limited success or yielded disappointing results. There has been a strong dependence on seismic data to interpret stratal ages and the regional depositional history because of the limited number of wells, which are all in the more proximal region. In October 2017, the International Ocean Discovery Program Expedition 369 drilled a hole at Site U1512 that straddled the Australian Geological Survey Organisation Survey s065 line 06 on the continental slope, ~67 km south-east of the Jerboa 1 well. The recovered core is the most extensive lithological dataset acquired from the basin and consists of a 10 m thick Pleistocene ooze overlying a 690 m succession of Turonian–Santonian strata. The Cretaceous strata consist of silty claystone with a few thin beds of glauconitic and sideritic sandstone (<32 cm thick). The Tiger Supersequence is substantially thicker than had been anticipated. Preliminary palynofacies analysis indicates a prevailing dysoxic marine environment, with the assemblage dominated by phytoclasts (40–90% of the assemblage). This may have been a consequence of high rates of freshwater runoff into the restricted basin. Rapid sedimentation rates (up to 260 m/Myr), the silt content (2–25%) and the palynofacies suggest the strata were deposited primarily by hyperpycnal and hypopycnal flows. These new datasets will provide a means to re-evaluate the palaeogeography of the basin and its resource potential.

Some of Australia’s deepwater frontiers are opening up for exploration, with existing and new companies taking acreage positions. Despite favourable fiscal terms and political stability, interest levels have not matched those in international hot spots due to key differences in perceived prospectivity.In this paper, Australia’s deepwater plays in the Northern Carnarvon Basin are compared and contrasted with deepwater plays in the Gulf of Mexico and offshore Mauritania. This comparison is largely based on Woodside Energy Ltd’s exploration pursuits in these areas.The Northern Carnarvon Basin deepwater plays are principally an extension of shallower water petroleum fairways, submerged to greater water depths by the absence of the Tertiary progradational, carbonate shelf sequence. Trap types and reservoir-seal pairs in the deepwater prospects are similar to their shallow water counterparts, but extensive deepwater areas carry an increased exploration risk due to the absence of this shelf overburden to load the Jurassic source rocks into the oil expulsion window. Hydrocarbons generated typically comprise dry gas from deeper Triassic source rocks, often trapped in sub-commercial quantities. Although the basin lacks a world class, widespread, oil-generating source rock, recent deepwater commercial oil discoveries in the Exmouth Sub-basin indicate the existence of a localised sweet spot associated with a Late Jurassic depocentre, similar to the proven Barrow-Dampier Subbasins located in shallower waters.In contrast, Woodside’s deepwater Gulf of Mexico and offshore Mauritania plays combine deepwater depositional systems with present day deepwater. They have reservoir-quality turbidite sandstones, well imaged on excellent quality 3D seismic, sealed by deep marine shales and charged by world class, organic-rich, prolific source rocks. Salt tectonics, shale diapirism and sloperelated slumping and thrusting have generated appealing structural styles, resulting in multiple play types and a density of prospects and leads not seen in Australia’s deepwater frontiers to date.Although elements of these plays are present at some locations in Australia’s deepwater, nowhere yet have all the required exploration ingredients for a major oil province been found juxtaposed as in the proven Gulf of Mexico and the highly prospective offshore Mauritania. Political stability and relatively favourable fiscal terms remain essential in attracting the exploration investment dollar to Australia’s deepwater.

The Great Australian Bight (GAB) represents one of Australia’s most prospective frontier hydrocarbon exploration regions. Its largest subregion – the Ceduna sub-basin – is a deep (slope to abyss) area of 126 300 km2 with a 15-km deep sedimentary sequence that remains effectively untested. Knowledge of the Ceduna sub-basin’s geology is rapidly evolving following recent collection of 3D seismic datasets, but many questions remain about its geological evolution. The composition of the seabed biota and its ecology in the deep GAB was virtually unknown. To address a range of geological and biological questions, the multidisciplinary Great Australian Bight Deepwater Marine Program aims to build a more comprehensive regional understanding of the geology of the deep (~700–5437 m) GAB, with a focus on rocky outcrops, segif and volcanic seamounts, and to document aspects of the biota and benthic ecology for the first time. A field campaign of 63 days in 2015 aboard the RV Investigator and a second support vessel for an Autonomous Underwater Vehicle completed a detailed mapping of 10 225 km2 of seabed. In addition, physical geological and biological sampling collected 1.3 tonnes of volcanic and sedimentary rocks and over 25 553 biological specimens. A surprisingly complex deep-water sedimentary environment was revealed, including several previously unmapped deep-water canyons and 10 previously unmapped volcanic seamounts. A total of 430 species were collected, of which nearly half appeared to be unknown to science. This paper uses results from this survey to provide insights into the geological processes that have shaped the GAB, and briefly describes the makeup of biological assemblages present on the seabed.

The Exmouth Sub-basin is part of the Northern Carnarvon Basin, offshore north-west Australia, and has undergone a complex tectonic history. Hydrocarbon exploration resulted in the discovery of a variety of oil and gas accumulations; however, their distribution and charge history from different petroleum systems is still poorly understood due to limited knowledge of the deeper basin architecture. The basin-wide, long-offset, broadband 2017 Exmouth 3D multiclient seismic dataset allowed a seamless interpretation into this deeper section. This work revealed new insights on the tectono-stratigraphic evolution of the Exmouth Sub-basin. Mesozoic extension, that was restricted to the latest Triassic, was followed by a sag phase with homogeneous, shale-dominated deposition, resulting in source rock potential for the entire Jurassic section. These findings, together with potential field modelling, were integrated into this first basin-wide 3D petroleum system model to better constrain the thermal history and petroleum systems. The model improved our understanding of the complex charge history of hydrocarbon fields. It predicts that hydrocarbon expulsion from Late Jurassic source rocks continued into the Late Cretaceous, a period when the regional Early Cretaceous Muderong Formation was an efficient seal rock. This implies that, in addition to long-distance, sub-Muderong migration, vertical, short-distance migration may have contributed significant petroleum charge to the discovered accumulations in the southern Exmouth Sub-basin. The model also predicts additional prospective areas: fault-seal structures within Early Cretaceous intervals north of the Novara Arch, intra-formational Late Jurassic sandstones north of the current fields (with low biodegradation risk) and Triassic reservoirs along the basin margins and north of the Jurassic depocentre.

Around the end of the twentieth century, awareness grew that, in addition to the Taranaki Basin, other unexplored basins in New Zealand’s large exclusive economic zone (EEZ) and extended continental shelf (ECS) may contain petroleum. GNS Science initiated a program to assess the prospectivity of more than 1 million square kilometres of sedimentary basins in New Zealand’s marine territories. The first project in 2001 acquired, with TGS-NOPEC, a 6,200 km reconnaissance 2D seismic survey in deep-water Taranaki. This showed a large Late Cretaceous delta built out into a northwest-trending basin above a thick succession of older rocks. Many deltas around the world are petroleum provinces and the new data showed that the deep-water part of Taranaki Basin may also be prospective. Since the 2001 survey a further 9,000 km of infill 2D seismic data has been acquired and exploration continues. The New Zealand government recognised the potential of its frontier basins and, in 2005 Crown Minerals acquired a 2D survey in the East Coast Basin, North Island. This was followed by surveys in the Great South, Raukumara and Reinga basins. Petroleum Exploration Permits were awarded in most of these and licence rounds in the Northland/Reinga Basin closed recently. New data have since been acquired from the Pegasus, Great South and Canterbury basins. The New Zealand government, through Crown Minerals, funds all or part of a survey. GNS Science interprets the new data set and the data along with reports are packaged for free dissemination prior to a licensing round. The strategy has worked well, as indicated by the entry of ExxonMobil, OMV and Petrobras into New Zealand. Anadarko, another new entry, farmed into the previously licensed Canterbury and deep-water Taranaki basins. One of the main results of the surveys has been to show that geology and prospectivity of New Zealand’s frontier basins may be similar to eastern Australia, as older apparently unmetamophosed successions are preserved. By extrapolating from the results in the Taranaki Basin, ultimate prospectivity is likely to be a resource of some tens of billions of barrels of oil equivalent. New Zealand’s largely submerged continent may yield continent-sized resources.

Abstract. As host to several world-class sediment-hosted Pb–Zn deposits and unknown quantities of conventional and unconventional gas, the variably inverted 1730–1640 Ma Calvert and 1640–1575 Ma Isa superbasins of northern Australia have been the subject of numerous seismic reflection studies with a view to better understanding basin architecture and fluid migration pathways. These studies reveal a structural architecture common to inverted sedimentary basins the world over, including much younger examples known to be prospective for oil and gas in the North Sea and elsewhere, with which they might be usefully compared. Such comparisons lend themselves to suggestions that the mineral and petroleum systems in Paleo–Mesoproterozoic northern Australia may have spatially, if not temporally overlapped and shared a common tectonic driver, consistent with the observation that basinal sequences hosting Pb–Zn mineralization in northern Australia are bituminous or abnormally enriched in hydrocarbons. Sediment-hosted Pb–Zn mineralization coeval with basin inversion first occurred during the 1650–1640 Ma Riversleigh Tectonic Event towards the close of the Calvert Superbasin with further pulses taking place during and subsequent to the onset of the 1620–1580 Ma Isa Orogeny and final closure of the Isa Superbasin. Mineralization is typically hosted by the post-rift or syn-inversion fraction of basin fill, contrary to existing interpretations of Pb–Zn ore genesis where the ore-forming fluids are introduced during the rifting or syn-extensional phase of basin development. Mineralizing fluids were instead expelled upwards during times of crustal shortening into structural and/or chemical traps developing in the hangingwalls of inverted normal faults. Inverted normal faults predominantly strike NNW and ENE, giving rise to a complex architecture of compartmentalized sub-basins whose individual uplifted basement blocks and doubly plunging periclinal folds exerted a strong control not only on the distribution and preservation of potential trap rocks but the direction of fluid flow, culminating in the co-location and trapping of mineralizing and hydrocarbon fluids in the same carbonaceous rocks. An important case study is the 1575 Ma Century Pb–Zn deposit where the carbonaceous host rocks served as both a reductant and basin seal during the influx of more oxidized mineralizing fluids, forcing the latter to give up their Pb and Zn metal. A transpressive tectonic regime in which basin inversion and mineralization were paired to folding, uplift, and erosion during arc–continent or continent–continent collision, and accompanied by orogen-parallel extensional collapse and strike-slip faulting best accounts for the observed relationships.

NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland.

The Stokes gas field is located in South West Queensland permit ATP 259P, close to the South Australia/Queensland state border. It was discovered and successfully appraised by the Stokes-1,-2 and -3 wells drilled during 1993 and early 1994. Productive zones, with DST flow rates of up to 237 x 103m3/d, are present in the Early Permian Epsilon and Patchawarra formations with moderate gas liquids contents present in the higher reservoirs. A total net pay thickness of 63 m occurs in Stokes-2. Generally, reservoir quality is moderate to good with core permeabilities occasionally exceeding one darcy. Some low deliverability Patchawarra Formation reservoirs are present which contain greater than 20 per cent kaolin. These microporous reservoirs are characterised by low resistivity responses similar to that of water saturated reservoirs.The field's discovery coincided with the onset of renewed South West Queensland gas exploration. Seismic data were recorded in 1990 and 1992 to mature the Stokes prospect to drillable status. The structure had been recognised as being highly prospective due to its regional setting. Proved and probable gas-in-place exceeds 5.7 x 109 m3 which approximates the highside case estimated from pre-drill probabilistic reserves distributions.Comprehensive reservoir pressure data were obtained from each well and were instrumental in locating appraisal wells and demonstrating that reservoirs are filled to the structural spill point. The Stokes-3 results indicate that some fault compartmentalisation may occur suggesting a more complex structure than originally mapped. Isolation of other reservoirs may also occur between Stokes-1 and -2.

The acquisition and depth imaging of almost 20400 km2 of broadband seismic data in the Great Australian Bight has created an excellent dataset fit for quantitative interpretation. This new dataset was derived from a merge of 12400 km2 of 2011 vintage conventional streamer data in an almost seamless manner with 8000 km2 of 2014 vintage dual-sensor streamer data. The Ceduna Sub-basin is the main depocentre of the Bight Basin. It lies adjacent to the continental shelf and slope and is covered by two broad bathymetric terraces in water depths ranging from <200 to >4000 m. A potentially prospective Late Jurassic syn-rift to Late Cretaceous post-rift sedimentary succession (fluvial to paralic sediments) >15 km thick is imaged with remarkable quality and resolution. Features of particular interest include large stacked fan and channel systems, as well as simple, structurally closed formations. Careful survey design and execution optimised efficiency, enabling each survey to be acquired in less than one season. Particular attention was given to amplitude versus offset and phase compliance, including customised flows to overcome a paucity of well control in this frontier area. Optimised preprocessing, velocity model building and survey merging were applied to ensure structural and depth integrity in the final images. Regional and targeted mapping and quantitative interpretation results testify to the value of the multifaceted geophysical and geological disciplines used in the overall project execution.

Sumatran fault in western Indonesia is one of the largest strike-slip fault in the world. The fault was formed as a result of the slip partitioning of the oblique convergence between the Indo-Australian and Eurasian plate along the Sunda trench. The right-lateral movement of the fault is accomodated by 19 fault segments that dissects the entire Sumatra island. We study the Aceh fault segment, which is located at the northernmost parts of the fault. The Aceh fault segment spans 250 km long passing through three districts: West Aceh, Pidie Jaya, and Aceh Besar and is affecting a total of ~546.143 population in the area. The current segmentation model assumes that Aceh fault segment acts as a single fault segment, which would generate closer to a M8 earthquake. This estimation is inconsistent with the ~M6-7 historical earthquake data. We conduct a detailed active fault mapping using the ~8 m resolution digital elevation model of DEMNAS and the sub-m DEM data from UAV-based photogrammetry to resolve the segmentation model of this fault. Our study indicate that the Aceh fault segment can be divided into 8 subsegments: Beutong, Kuala Tripa, Geumpang, Mane, Tangse, Jantho, Indrapuri, and Pulo Aceh. The fault kinematics identified in the field is consistent with right-lateral faulting. We measured cumulative displacement of geomorphic features (channels and ridges) ranging from 12.7 to 1931 m at some area. Findings of our study provide better estimation of the fault geometry and the maximum magnitude of potential earthquake along the Aceh fault segment as well as recommendation of prospective sliprate study sites. These informations are important for the development of seismic hazard analysis of the area.

The offshore Sydney Basin is unique frontier acreage because it is adjacent to Australia's largest gas and petroleum market on the east coast of New South Wales. Although the onshore Sydney Basin has been tested by more than 100 petroleum exploration wells, no wells have been drilled offshore.New South Wales Permit NSW/P10 has an area of 9419 km2 and extends over the offshore northern and central Sydney Basin which contains Upper Carboniferous to Middle Triassic lithiclastic and siliciclastic sedimentary rocks and volcanics. Maximum depth to magnetic basement in NSW/P10 is greater that 9 km in the southern Macquarie Syncline and south of the New England Fold Belt at the continental margin. Recent seismic reprocessing and aeromagnetic surveying have focused the exploration effort on northern NSW/P10 where thick (greater than 1600 m) Upper Permian section containing source and reservoir facies is predicted. Other areas in the permit are less prospective because of widespread intrasedimentary magnetic bodies or the absence by erosion of Upper Permian and Triassic section.The Sydney Basin is an exhumed basin that reached its maximum depth of burial in the Early Cretaceous prior to basinwide uplift of 1.5-3.5 km during the Tasman Sea rifting. The magnitude and timing of the exhumation can be demonstrated with fluid inclusion, magnetisation, fission track and vitrinite reflectance data. The presence of commercial quantities of oil or gas in Upper Permian reservoirs depends on trap integrity having been maintained during the epeirogeny, or the re-migration of hydrocarbon into new traps.

Sequence biostratigraphy is a relatively new discipline that has rapidly expanded in parallel with the development of sequence stratigraphy. Sequence bios- tratigraphic concepts have resulted in significant improvements in our ability to calibrate biozones, correlate and determine ages of sedimentary units, and to estimate environments of deposition. Significant advances in the development of integrated biostratigraphic methods and knowledge during the past 20 years are now being rapidly integrated into the physical framework provided by depositional sequences. Sequence stratigraphy provides a physical framework consisting of a predictable hierarchy of correlation surfaces, ranging from sequence boundaries to parasequence boundaries, within which biostratigraphic observations may be placed. These correlation surfaces define chronostratigraphic units with varying degrees of lateral extent that can be used to assess, using time-distance grids, the relative position of biozone 'tops' or 'bases'. They also provide a physical link between the open-ocean planktonic microfossil chronozones and chronozones developed in paralic and non-marine strata. In addition, the delineation of large, apparently sudden, water depth changes across downlap surfaces, associated with condensed sections, has resulted in more accurate and precise paleobathymetric estimation in exploration wells. Recognition and biostratigraphic 'fingerprinting' of major water depth changes are essential for correlation through intensely faulted areas.The rate of return from biostratigraphic and geochemi- cal sampling is generally poor primarily because of the lack of emphasis on the importance of developing and maintaining well planned sampling strategies and programs throughout an exploration drilling program. The design of biostratigraphic and geochemical sampling strategies has been improved by sequence stratigraphic concepts. Biostratigraphic sample quality (high) is inversely proportional to sedimentation rate (low). Sequence biostratigraphy provides a consistent, predictable, method of recognising low sedimentation rate units in the subsurface using a variety of tools, ranging from seismic to well log facies analysis.Some of the basic principles of sequence biostratigraphy are illustrated using an example from the Carnarvon Basin. The Barremian A. cinctum andM. australis dinocyst Acme and Oppel zones respectively, appear to be strongly associated with distinct environments. Consequently, it is difficult to calibrate them to the AGSO timescale and to use them regionally as reliable zones to subdivide the Barremian. Abundant numbers of A. cinctum appear to be restricted to specific regions of the Carnarvon dominated by shallower marine conditions and associated with the infilling of major incised river systems. Further biostratigraphic subdivisions within the Early Cretaceous and specifically the M. australis - A. cinctum interval are warranted, especially in light of the number of plays and prospects defined and discoveries made within this interval of the Carnarvon Basin. More detailed biostratigraphic work coupled with regional sequence stratigraphy and a more focussed sampling strategy should produce a high quality age-model for this prospective interval that had not received significant attention until recently.

CNOOC Turns Taps on Bohai Bay Fields Volumes are flowing from two new CNOOC-operated field developments in the Bohai Sea, offshore China. Production began at the Luda 5-2 oil field north phase 1 project in Liaodong Bay. The field is in an average water depth of around 32 m. CNOOC installed one thermal recovery wellhead platform and one production platform, and connected processing facilities serving the Suizhong 36-1 oil field. The company plans to drill a total of 26 production and two water-source wells, with peak crude oil production of 8,200 B/D targeted for 2024. Oil also is flowing at the Kenli 6-1 oil field 4-1 block development in the southern Bohai Sea. A new wellhead platform in about 17 km of water is connected to processing facilities at the Bozhong 34-9 oil field. CNOOC plans a total of seven producer and five water-injector wells at Kenli 6-1, with peak oil production later this year of around 4,000 B/D. CNOOC holds a 100% stake in both projects. Sailaway for GTA FPSO Expected by Year-End A BP executive told conference goers in Senegal recently that the FPSO destined for that country’s Greater Tortue Ahmeyim (GTA) gas project is expected to leave China prior to year-end. BP Executive Vice President for Production and Operations Gordon Birrell added that the first phase of the GTA project is 80% complete. The main function of the FPSO will be to remove water and condensate and reduce impurities in the gas stream before exporting processed gas to a nearby FLNG facility and domestic gas offtake. BP and Kosmos Energy are leading the development of GTA and Yakaar-Teranga, Senegal’s first natural gas projects. GTA straddles the border between Senegal and Mauritania. Phase 1 of the planned development is expected to start delivering gas by the end of 2023. Birrell added that BP is in discussions with Senegal and Mauritania about GTA’s second phase and other projects in both countries, but did not get into specifics, according to Reuters. Phase two should double expected production from 2.5 to 5.0 mtpa. ReconAfrica, NAMCOR Reach Target Depth on Namibia Well Reconnaissance Energy Africa and its joint venture partner NAMCOR, the state oil company of Namibia, confirmed the third stratigraphic test well in the Kavango basin of northeast Namibia, 1819/8-2, reached target depth. The well was drilled to a total depth of 2056 m reaching all geological targets. However, the duo did not reveal what was found in the well. Instead, the pair said current operations were focused on well data capture and initiating analysis of the data. Company-owned rig Jarvie-1 will remain on site until logging and coring operations are completed. A vertical seismic profile tool will also be run to total depth to tie into the 2D seismic program. Processing of the second phase of 761 km of 2D seismic is near completion, where early results are being used to refine drilling locations for the upcoming stratigraphic wells. The next well of this planned continuous drilling program was scheduled to have the rig on location by the end of last month. Pantheon Resources Alaska Discovery Deemed “World Class” Pantheon Resources has uncovered a “world-class” oil discovery on its Theta West acreage in Alaska, according to independent consultants brought in to assess the area’s potential. Baker Hughes Advanced Hydrocarbon Stratigraphy (AHS) was charged with compiling a report based on data collated after a successful appraisal well drilled early this year. The firm believes there is a continuous column of oil-bearing cuttings of at least 1,360 ft that is host to a light crude in the order of 37–39 °API. The AHS report concluded there are “abundant good-quality reservoirs” with an “ultimate, nonpermeable seal” at 7,070 ft. Pantheon said the results are supportive of analyses of cuttings from previous work on the acreage on Alaska’s prolific North Slope. The company estimated the project, which is close to infrastructure, is host to 17 billion bbl of which 10%, or 1.7 billion bbl, is deemed recoverable. Invictus Well in Zimbabwe a “Game Changer” The Mukuyu-1 exploration well being drilled in Zimbabwe by Australian firm Invictus Energy in partnership with the government is being called “a game changer” for the country by President Emmerson Mnangagwa. The well is in license SG 4571, which covers 250,000 acres located in the most prospective portion of the Cabora Bassa Basin in northern Zimbabwe. The license is currently in the second exploration period which runs to June 2024. Invictus entered into an agreement with the Zimbabwe government in March 2022 to increase the license area sevenfold to 1.77 million acres. Previously explored by Mobil Oil, the project contains the largest undrilled structure in onshore Africa. The Muzarabani anticline feature has more than 200 km2 under closure and up to 1500 m vertical relief at favorable depths for conventional oil and gas. Invictus completed the acquisition of 840 km of high-resolution infill 2D seismic data ahead of spudding the well using Exalo Rig 202 in August. Drilling Results a Mixed Bag for APA Offshore Suriname APA Corporation has made an oil discovery offshore Suriname with its Baja-1 well in Block 53 but came away empty with a probe in Block 58. Baja-1 was drilled to a depth of 5290 m and encountered 34 m of net oil pay in a single interval within the Campanian. Preliminary fluid and log analysis indicates light oil with a gas/oil ratio (GOR) of 1,600 to 2,200 scf/bbl, in good-quality reservoir. The discovery at Baja-1 is a down-dip lobe of the same depositional system as the Krabdagu discovery, 11.5 km to the west in Block 58. Evaluation of openhole well logs, cores, and reservoir fluids is ongoing. The success at Baja marks the sixth oil discovery in which APA has participated in offshore Suriname and the first on Block 53. The company said the result confirms its geologic model for the Campanian in the area and helps to de-risk other prospects in the southern portion of both Blocks 53 and 58. APA recently received regulatory approval regarding an amendment to the Block 53 production-sharing contract, which provides options to extend the exploration period by up to 4 years. The company is currently proceeding with formalizing the first one-year extension, for which all work commitments are complete. APA is operator and holds a 45% working interest in Block 53; partners Petronas and CEPSA hold 30% and 25% stakes, respectively. Baja-1 was drilled using drillship Noble Gerry de Souza in water depths of approximately 1140 m. The rig will mobilize to Block 58 following the completion of current operations, where it will drill the Awari exploration prospect, approximately 27 km north of the Maka Central discovery. APA was not as fortunate with its Dikkop exploration well in Block 58. The well encountered water-bearing sandstones in the targeted interval and has been plugged and abandoned. Operator TotalEnergies holds a 50% working interest, while APA holds the remaining 50% stake. The drillship Maersk Valiant will be moving to the Sapakara field to drill a second appraisal well at Sapakara South, where the joint venture conducted a successful flow test late last year. Helix Energy Solutions Secures Production, P&A Work With Thunder Hawk Buy Helix Energy Solutions Group subsidiary Deepwater Abandonment Alternatives (DAA) acquired all of MP GOM’s 62.5% interest in Mississippi Canyon Block 734, comprising three wells and related subsea infrastructure, collectively known as the Thunder Hawk field. MP GOM is a subsidiary of Murphy Oil. Financial terms of the deal were not disclosed. “This acquisition furthers Helix’s energy transition business model by taking on decommissioning obligations in exchange for production revenues,” said Owen Kratz, president and chief executive of Helix. “We have long communicated our unique position as a qualified offshore field operator that can also assume and efficiently discharge decommissioning obligations. We continue to pursue opportunities that enable us to enhance and extend the life of existing reserves and safely perform the related decommissioning of the infrastructure in transactions that allow producers to remove noncore assets from their balance sheets.” Under the terms of the transaction, Helix receives the benefit of ownership of MP GOM’s interest, with a 1 November 2021 effective date purchase price adjustment resulting in nominal cash paid by MP GOM at closing, in exchange for the assumption of MP GOM’s abandonment obligations at the Thunder Hawk Field. In addition to anticipated future production revenue, DAA will operate the Thunder Hawk field with Helix eventually expected to perform the required plug and abandonment operations. Kolibri Continues Tishamingo Program in Oklahoma Kolibri Global Energy has completed the location work for the Glenn 16-3H and Brock 9-3H wells, which are the third and fourth wells in its 2022 drilling program. A fifth location is also being prepped. All three wells in the Tishamingo area of the SCOOP play are planned to be drilled back-to-back, and the completion operations for the Glenn 16-3H and Brock 9-3H wells have been tentatively scheduled for the first week of October. Neptune Energy Confirms New Discovery in the Gjøa Area Neptune Energy and its partners announced a new commercial discovery at the Ofelia exploration well (PL 929), close to the Gjøa field in the Norwegian sector of the North Sea. Neptune has completed drilling of the Ofelia well, 35/6-3 S, and encountered oil in the Agat formation. The preliminary estimate of recoverable volume is in the range of 16 to 39 million BOE. In addition to the Agat volumes, north of the well there is an upside of around 10 million BOE recoverable gas in the shallower Kyrre formation, which brings the total recoverable volume to approximately 26 to 49 million BOE. Located 15 km north of the operated Gjøa platform, at a water depth of 344 m, Ofelia will be considered for development as a tieback to Gjøa, in parallel with the company’s recent oil and gas discovery at Hamlet. The Ofelia well, drilled by Odfjell-operated semisubmersible Deepsea Yantai, confirmed an oil/water contact at 2639 m total vertical depth. It is the third discovery by Neptune Energy in the Agat formation, a reservoir which until recently was not part of established exploration models on the Norwegian Shelf. The first was at the Duva field, which is now onstream and being operated by Neptune. The second was the company’s discovery at Hamlet, with estimated recoverable volumes between 8 and 24 million BOE.

Transocean Harsh-Environment Rig Scoops Contract Extension Equinor extended Transocean’s contract for use of the harsh-environment semisubmersible Transocean Spitsbergen. The additional nine wells plus two, one-well options extension is valued at $181 million and is expected to begin in October 2023. The work will keep the rig busy off Norway until April 2025. In the fall of next year, the rig is scheduled to start drilling a trio of production wells for the Haltenbanken Vest Unit, which is part of the Kristin South area in the Norwegian Sea. Transocean Spitsbergen has been working consistently for Equinor since 2019. Equinor Wildcat Comes Up Empty Equinor will plug and abandon its Cambozola exploration well in License PL1049 offshore Norway after failing to encounter commercial hydrocarbons. Exploration well 34/9-1S was targeting Lower Cretaceous turbidite sand lobes in the northern North Sea and had the potential to be a play opener, according to well partner Longboat Energy. The exploration will continue with the Oswig and Copernicus wells, both expected to spud this summer. The Cambozola well was drilled to a total vertical depth of 4393 m using Odjfell Drilling semisubmersible Deepsea Stavanger. Background gas readings were recorded throughout the overlying section, but the well failed to encounter effective reservoir. Equinor is analyzing the data collected to understand the observed bright seismic amplitude anomaly and any remaining Lower Cretaceous prospectivity in the area. Longboat had previously referred to Cambozola as a potential play opener and one of the largest gas prospects to be drilled in Norway in 2022. Gross unrisked mean prospective resources for the entire Cambozola prospect have been estimated at 159 million BOE. Western Gas’ Sasanof-1 Exploration Well Disappoints Western Gas failed to encounter hydrocarbons with its Sasanof-1 exploration well offshore Western Australia. The well was drilled to a total depth of 2390 m by semisubmersible Valaris MS-1, but no gas reservoirs were intersected. The well will be permanently plugged and abandoned. The Sasanof prospect was estimated to hold 7.2 Tcf gas and 176 million bbl of condensate. The prospect was seen as potential supply for the NW Shelf LNG project. Vaalco Adds Reserves at Etame off Gabon Vaalco Energy encountered multiple hydrocarbon-bearing sands with its South Tchibala 1HB-ST well drilled from the Avouma platform in the Etame field offshore Gabon. The well struck 18 m of hydrocarbons in the Dentale D1 sand, which is analogous to the Deep Dentale producing field in North Tchibala with similar porosity and permeability. Another 15 m of hydrocarbons was intersected in the Dentale D9. The well will be completed in the D1 sand and was scheduled to be online in June, while the D9 will be cased for future completion. The well also penetrated a thin section of Gamba sand which will not be economically feasible to complete. Current Etame production is fed through the recently extended FPSO Petroleo Nautipa. Success with the South Tchibala 1HB-ST potentially adds new future drilling locations in the Deep Dentale trend across the Etame block. Eni, TotalEnergies Begin Drilling Off Cyprus Partners Eni and TotalEnergies have begun drilling a natural gas wildcat dubbed Cronos-1 in Block 6 offshore Cyprus. The well, originally planned for 2020, was derailed by the COVID-19 pandemic. Vantage Drilling drillship Tungsten Explorer is on location and is conducting the drilling operations. In 2018, the partnership struck gas at the Calypso well in another part of Block 6. That well proved that the carbonate play present in Eni’s Zoar field off Egypt extended to the Cypress exclusive economic zone. Zoar was discovered in 2015 and is the biggest gas discovery to date in the Mediterranean Sea. Calypso-1 was drilled to a total depth of 3827 m and encountered an extended gas column in Miocene- and Cretaceous-aged sands. Eni operates Block 6 with a 50% participation interest. TotalEnergies holds the remaining 50% stake. ADNOC Makes Three Onshore Discoveries Abu Dhabi National Oil Company (ADNOC) has unveiled three new oil discoveries including one at Bu Hasa, Abu Dhabi’s biggest onshore field, with a crude oil production capacity of 650,000 B/D. The discovery in Bu Hasa includes 500 million bbl of oil from an exploration well in the field. The second oil find was in Abu Dhabi’s Onshore Block 3, operated by Occidental, and is estimated to be around 100 million bbl of oil in place. The onshore Al Dhafra Petroleum Concession yielded the third discovery—around 50 million bbl of light sweet Murban-quality crude. Ecopetrol, Oxy Prep Development Quartet Ecopetrol has an agreement in place to develop four deepwater blocks with a subsidiary of Occidental. The four blocks are located in deep waters some 150 km off Colombia’s northern Caribbean coast. Ecopetrol will take a 40% stake in the blocks while Occidental subsidiary Anadarko Colombia will hold the remaining 60% stake and will serve as the blocks’ operator. The deal remains subject to approval from Colombia’s Ministry of Mines and Energy. Equinor, ExxonMobil Plan Bacalhau Expansion off Brazil Equinor and partner ExxonMobil are considering adding a second drilling rig and a second floating production platform for the next phase of the Bacalhau development in the Santos basin, along with a 100-mile-long gas pipeline, according to Reuters. The companies want to boost future production from Bacalhau, Equinor’s largest project outside of Norway. A new appraisal well is planned in the north of the field next year “to better understand the reserves base for the Phase 2 development,” according to Equinor, and the partners are assessing awarding a contract for a second drilling rig. The partners sanctioned the $8-billion project a year ago. The field is situated across two licenses, BM-S-8 and Norte de Carcará. The resource is a high-quality carbonate reservoir containing light oil. The development will comprise 19 subsea wells tied back to an FPSO located at the field. The planned FPSO be one of the largest in Brazil with a production capacity of 220,000 B/D and 2 million bbl in storage capacity. The stabilized oil will be offloaded to shuttle tankers, and the gas from Phase 1 will be reinjected in the reservoir. First oil is expected in 2024. Equinor Transfers Krafla Operatorship to Aker BP Equinor and Aker BP have signed a memorandum of understanding (MoU) for transfer of the Krafla operatorship from Equinor to Aker BP, making Aker BP the operator of all discoveries in the NOAKA area: Krafla, Fulla, and North of Alvheim. Equinor and Aker BP are operators of one field development project each in the area and have agreed that one operator will be the best solution for further development. The MoU states that the owners of the relevant licenses will apply to the ministry for change of operator. A transfer of operatorship will be carried out when the investment decision has been approved by the license partners and the plan for development and operation has been submitted to the authorities. Equinor will still be a major license partner in the area and will retain its existing share of 50% in Krafla and 40% in the Fulla license. The companies will jointly submit the PDOs for NOA Fulla and Krafla as planned by the end of the year. Energean Strikes Gas at Athena off Israel UK-based Energean has discovered gas with its Athena probe in Block 12, 20 km from Tanin A in 1769 m of water. The probe was drilled in 51 days and encountered a gross hydrocarbon column of 156 m in the primary target. Preliminary analysis indicates that the Athena discovery contains recoverable gas volumes of 8 Bcm on a standalone basis. Energean will conduct analysis to refine the full resource potential (including volumes contained within thinner sands between the main reservoir units) and to confirm the liquids content of the discovery. The Athena well has been suspended as a future production well. Commercial hydrocarbons were not discovered in the deeper secondary target. Athena can be commercialized in the near term via tieback to the Energean Power FPSO, enhancing the profitability of the Karish-Tanin development. Alternatively, it could form part of a new development called the Olympus Area which consists of Block 12 and additional prospects on the Tanin lease. The discoveries and prospects in this area lie along the same geological trend; Athena was drilled on the same direct hydrocarbon indicator as Tanin. Energean is confident that the Athena discovery has de-risked the A, B, and C sands in the remaining prospects of the Olympus Area, estimated to be 50 Bcm of mean unrisked prospective resources. This estimate excludes the liquids component as well as any gas upside in the thinner sands between the main reservoir units. Drillship Stena IceMAX has moved to the Karish Main-04 appraisal well and will complete the Karish North development well.

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.

Unconventional energy sources have become increasingly important to the global energy mix. These include coal seam gas, shale gas and shale oil. The unconventional gas industry was pioneered in the United States and embraced following the first oil shock in 1973 (Rogers). As has been the case with many global resources (Hiscock), many of the same companies that worked in the USA carried their experience in this industry to early Australian explorations. Recently the USA has secured significant energy security with the development of unconventional energy deposits such as the Marcellus shale gas and the Bakken shale oil (Dobb; McGraw). But this has not come without environmental impact, including contamination to underground water supply (Osborn, Vengosh, Warner, Jackson) and potential greenhouse gas contributions (Howarth, Santoro, Ingraffea; McKenna). The environmental impact of unconventional gas extraction has raised serious public concern about the introduction and growth of the industry in Australia. In coal rich Australia coal seam gas is currently the major source of unconventional gas. Large gas deposits have been found in prime agricultural land along eastern Australia, such as the Liverpool Plains in New South Wales and the Darling Downs in Queensland. Competing land-uses and a series of environmental incidents from the coal seam gas industry have warranted major protest from a coalition of environmentalists and farmers (Berry; McLeish). Conflict between energy companies wanting development and environmentalists warning precaution is an easy script to cast for frontline media coverage. But historical perspectives are often missing in these contemporary debates. While coal mining and natural gas have often received “boosting” historical coverage (Diamond; Wilkinson), and although historical themes of “development” and “rushes” remain predominant when observing the span of the industry (AGA; Blainey), the history of unconventional gas, particularly the history of its environmental impact, has been little studied. Few people are aware, for example, that the first shale gas exploratory well was completed in late 2010 in the Cooper Basin in Central Australia (Molan) and is considered as a “new” frontier in Australian unconventional gas. Moreover many people are unaware that the first coal seam gas wells were completed in 1976 in Queensland. The first four wells offer an important moment for reflection in light of the industry’s recent move into Central Australia. By locating and analysing the first four coal seam gas wells, this essay identifies the roots of the unconventional gas industry in Australia and explores the early environmental impact of these wells. By analysing exploration reports that have been placed online by the Queensland Department of Natural Resources and Mines through the lens of environmental history, the dominant developmental narrative of this industry can also be scrutinised. These narratives often place more significance on economic and national benefits while displacing the environmental and social impacts of the industry (Connor, Higginbotham, Freeman, Albrecht; Duus; McEachern; Trigger). This essay therefore seeks to bring an environmental insight into early unconventional gas mining in Australia. As the author, I am concerned that nearly four decades on and it seems that no one has heeded the warning gleaned from these early wells and early exploration reports, as gas exploration in Australia continues under little scrutiny. Arrival The first four unconventional gas wells in Australia appear at the beginning of the industry world-wide (Schraufnagel, McBane, and Kuuskraa; McClanahan). The wells were explored by Houston Oils and Minerals—a company that entered the Australian mining scene by sharing a mining prospect with International Australian Energy Company (Wiltshire). The International Australian Energy Company was owned by Black Giant Oil Company in the US, which in turn was owned by International Royalty and Oil Company also based in the US. The Texan oilman Robert Kanton held a sixteen percent share in the latter. Kanton had an idea that the Mimosa Syncline in the south-eastern Bowen Basin was a gas trap waiting to be exploited. To test the theory he needed capital. Kanton presented the idea to Houston Oil and Minerals which had the financial backing to take the risk. Shotover No. 1 was drilled by Houston Oil and Minerals thirty miles south-east of the coal mining town of Blackwater. By late August 1975 it was drilled to 2,717 metres, discovered to have little gas, spudded, and, after a spend of $610,000, abandoned. The data from the Shotover well showed that the porosity of the rocks in the area was not a trap, and the Mimosa Syncline was therefore downgraded as a possible hydrocarbon location. There was, however, a small amount of gas found in the coal seams (Benbow 16). The well had passed through the huge coal seams of both the Bowen and Surat basins—important basins for the future of both the coal and gas industries. Mining Concepts In 1975, while Houston Oil and Minerals was drilling the Shotover well, US Steel and the US Bureau of Mines used hydraulic fracture, a technique already used in the petroleum industry, to drill vertical surface wells to drain gas from a coal seam (Methane Drainage Taskforce 102). They were able to remove gas from the coal seam before it was mined and sold enough to make a profit. With the well data from the Shotover well in Australia compiled, Houston returned to the US to research the possibility of harvesting methane in Australia. As the company saw it, methane drainage was “a novel exploitation concept” and the methane in the Bowen Basin was an “enormous hydrocarbon resource” (Wiltshire 7). The Shotover well passed through a section of the German Creek Coal measures and this became their next target. In September 1976 the Shotover well was re-opened and plugged at 1499 meters to become Australia’s first exploratory unconventional gas well. By the end of the month the rig was released and gas production tested. At one point an employee on the drilling operation observed a gas flame “the size of a 44 gal drum” (HOMA, “Shotover # 1” 9). But apart from the brief show, no gas flowed. And yet, Houston Oil and Minerals was not deterred, as they had already taken out other leases for further prospecting (Wiltshire 4). Only a week after the Shotover well had failed, Houston moved the methane search south-east to an area five miles north of the Moura township. Houston Oil and Minerals had researched the coal exploration seismic surveys of the area that were conducted in 1969, 1972, and 1973 to choose the location. Over the next two months in late 1976, two new wells—Kinma No.1 and Carra No.1—were drilled within a mile from each other and completed as gas wells. Houston Oil and Minerals also purchased the old oil exploration well Moura No. 1 from the Queensland Government and completed it as a suspended gas well. The company must have mined the Department of Mines archive to find Moura No.1, as the previous exploration report from 1969 noted methane given off from the coal seams (Sell). By December 1976 Houston Oil and Minerals had three gas wells in the vicinity of each other and by early 1977 testing had occurred. The results were disappointing with minimal gas flow at Kinma and Carra, but Moura showed a little more promise. Here, the drillers were able to convert their Fairbanks-Morse engine driving the pump from an engine run on LPG to one run on methane produced from the well (Porter, “Moura # 1”). Drink This? Although there was not much gas to find in the test production phase, there was a lot of water. The exploration reports produced by the company are incomplete (indeed no report was available for the Shotover well), but the information available shows that a large amount of water was extracted before gas started to flow (Porter, “Carra # 1”; Porter, “Moura # 1”; Porter, “Kinma # 1”). As Porter’s reports outline, prior to gas flowing, the water produced at Carra, Kinma and Moura totalled 37,600 litres, 11,900 and 2,900 respectively. It should be noted that the method used to test the amount of water was not continuous and these amounts were not the full amount of water produced; also, upon gas coming to the surface some of the wells continued to produce water. In short, before any gas flowed at the first unconventional gas wells in Australia at least 50,000 litres of water were taken from underground. Results show that the water was not ready to drink (Mathers, “Moura # 1”; Mathers, “Appendix 1”; HOMA, “Miscellaneous Pages” 21-24). The water had total dissolved solids (minerals) well over the average set by the authorities (WHO; Apps Laboratories; NHMRC; QDAFF). The well at Kinma recorded the highest levels, almost two and a half times the unacceptable standard. On average the water from the Moura well was of reasonable standard, possibly because some water was extracted from the well when it was originally sunk in 1969; but the water from Kinma and Carra was very poor quality, not good enough for crops, stock or to be let run into creeks. The biggest issue was the sodium concentration; all wells had very high salt levels. Kinma and Carra were four and two times the maximum standard respectively. In short, there was a substantial amount of poor quality water produced from drilling and testing the three wells. Fracking Australia Hydraulic fracturing is an artificial process that can encourage more gas to flow to the surface (McGraw; Fischetti; Senate). Prior to the testing phase at the Moura field, well data was sent to the Chemical Research and Development Department at Halliburton in Oklahoma, to examine the ability to fracture the coal and shale in the Australian wells. Halliburton was the founding father of hydraulic fracture. In Oklahoma on 17 March 1949, operating under an exclusive license from Standard Oil, this company conducted the first ever hydraulic fracture of an oil well (Montgomery and Smith). To come up with a program of hydraulic fracturing for the Australian field, Halliburton went back to the laboratory. They bonded together small slabs of coal and shale similar to Australian samples, drilled one-inch holes into the sample, then pressurised the holes and completed a “hydro-frac” in miniature. “These samples were difficult to prepare,” they wrote in their report to Houston Oil and Minerals (HOMA, “Miscellaneous Pages” 10). Their program for fracturing was informed by a field of science that had been evolving since the first hydraulic fracture but had rapidly progressed since the first oil shock. Halliburton’s laboratory test had confirmed that the model of Perkins and Kern developed for widths of hydraulic fracture—in an article that defined the field—should also apply to Australian coals (Perkins and Kern). By late January 1977 Halliburton had issued Houston Oil and Minerals with a program of hydraulic fracture to use on the central Queensland wells. On the final page of their report they warned: “There are many unknowns in a vertical fracture design procedure” (HOMA, “Miscellaneous Pages” 17). In July 1977, Moura No. 1 became the first coal seam gas well hydraulically fractured in Australia. The exploration report states: “During July 1977 the well was killed with 1% KCL solution and the tubing and packer were pulled from the well … and pumping commenced” (Porter 2-3). The use of the word “kill” is interesting—potassium chloride (KCl) is the third and final drug administered in the lethal injection of humans on death row in the USA. Potassium chloride was used to minimise the effect on parts of the coal seam that were water-sensitive and was the recommended solution prior to adding other chemicals (Montgomery and Smith 28); but a word such as “kill” also implies that the well and the larger environment were alive before fracking commenced (Giblett; Trigger). Pumping recommenced after the fracturing fluid was unloaded. Initially gas supply was very good. It increased from an average estimate of 7,000 cubic feet per day to 30,000, but this only lasted two days before coal and sand started flowing back up to the surface. In effect, the cleats were propped open but the coal did not close and hold onto them which meant coal particles and sand flowed back up the pipe with diminishing amounts of gas (Walters 12). Although there were some interesting results, the program was considered a failure. In April 1978, Houston Oil and Minerals finally abandoned the methane concept. Following the failure, they reflected on the possibilities for a coal seam gas industry given the gas prices in Queensland: “Methane drainage wells appear to offer no economic potential” (Wooldridge 2). At the wells they let the tubing drop into the hole, put a fifteen foot cement plug at the top of the hole, covered it with a steel plate and by their own description restored the area to its “original state” (Wiltshire 8). Houston Oil and Minerals now turned to “conventional targets” which included coal exploration (Wiltshire 7). A Thousand Memories The first four wells show some of the critical environmental issues that were present from the outset of the industry in Australia. The process of hydraulic fracture was not just a failure, but conducted on a science that had never been tested in Australia, was ponderous at best, and by Halliburton’s own admission had “many unknowns”. There was also the role of large multinationals providing “experience” (Briody; Hiscock) and conducting these tests while having limited knowledge of the Australian landscape. Before any gas came to the surface, a large amount of water was produced that was loaded with a mixture of salt and other heavy minerals. The source of water for both the mud drilling of Carra and Kinma, as well as the hydraulic fracture job on Moura, was extracted from Kianga Creek three miles from the site (HOMA, “Carra # 1” 5; HOMA, “Kinma # 1” 5; Porter, “Moura # 1”). No location was listed for the disposal of the water from the wells, including the hydraulic fracture liquid. Considering the poor quality of water, if the water was disposed on site or let drain into a creek, this would have had significant environmental impact. Nobody has yet answered the question of where all this water went. The environmental issues of water extraction, saline water and hydraulic fracture were present at the first four wells. At the first four wells environmental concern was not a priority. The complexity of inter-company relations, as witnessed at the Shotover well, shows there was little time. The re-use of old wells, such as the Moura well, also shows that economic priorities were more important. Even if environmental information was considered important at the time, no one would have had access to it because, as handwritten notes on some of the reports show, many of the reports were “confidential” (Sell). Even though coal mines commenced filing Environmental Impact Statements in the early 1970s, there is no such documentation for gas exploration conducted by Houston Oil and Minerals. A lack of broader awareness for the surrounding environment, from floral and faunal health to the impact on habitat quality, can be gleaned when reading across all the exploration reports. Nearly four decades on and we now have thousands of wells throughout the world. Yet, the challenges of unconventional gas still persist. The implications of the environmental history of the first four wells in Australia for contemporary unconventional gas exploration and development in this country and beyond are significant. Many environmental issues were present from the beginning of the coal seam gas industry in Australia. Owning up to this history would place policy makers and regulators in a position to strengthen current regulation. The industry continues to face the same challenges today as it did at the start of development—including water extraction, hydraulic fracturing and problems associated with drilling through underground aquifers. Looking more broadly at the unconventional gas industry, shale gas has appeared as the next target for energy resources in Australia. Reflecting on the first exploratory shale gas wells drilled in Central Australia, the chief executive of the company responsible for the shale gas wells noted their deliberate decision to locate their activities in semi-desert country away from “an area of prime agricultural land” and conflict with environmentalists (quoted in Molan). Moreover, the journalist Paul Cleary recently complained about the coal seam gas industry polluting Australia’s food-bowl but concluded that the “next frontier” should be in “remote” Central Australia with shale gas (Cleary 195). It appears that preference is to move the industry to the arid centre of Australia, to the ecologically and culturally unique Lake Eyre Basin region (Robin and Smith). 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Jackson. “Methane Contamination of Drinking Water Accompanying Gas-Well Drilling and Hydraulic Fracturing.” Proceedings of the National Academy of Sciences 108.20 (2011): 8172-8176. Perkins, T.K., and L.R. Kern. “Widths of Hydraulic Fractures.” Journal of Petroleum Technology 13.9 (1961): 937-949. Porter, Seton M. “Carra # 1:Testing Report, Methane Drainage of the Baralaba Coal Measures, A.T.P. 226P, Central Queensland, Australia.” Oct. 1977. Queensland Digital Exploration Reports. Company Report 6054_7. Brisbane: Queensland Department of Resources and Mines. 21 Feb. 2012 ‹https://qdexguest.deedi.qld.gov.au/portal/site/qdex/search?REPORT_ID=6054&COLLECTION_ID=999›. ———. “Kinma # 1: Testing Report, Methane Drainage of the Baralaba Coal Measures, A.T.P. 226P, Central Queensland, Australia.” Oct. 1977. Queensland Digital Exploration Reports. Company Report 6190_16. 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Poster G11 The Otway Basin is a northwest–southeast trending rift basin which spans from onshore Victoria and South Australia into the deep-water offshore. The prospective supersequences within the basin are largely of Cretaceous age that host three possible petroleum systems (Austral 1, 2 and 3). While there is production from onshore depocentres, and the inboard Shipwreck Trough, the majority of the offshore basin remains underexplored. Recent regional studies have highlighted the need for further work across the underexplored parts of the basin and here we focus on the offshore northwest Otway Basin, integrating reinterpreted historical well data, newly acquired and recently reprocessed seismic data. This new Well Folio consists of composite logs and supporting data, which includes interpreted lithologies, petrophysical analyses, the analysis of historic organic geochemistry and organic petrology. In addition, updated well markers are provided based on seismic interpretation and new biostratigraphy in key wells. This integrated study provides the basis for renewed prospectivity assessment in the northwest offshore portion of the Otway Basin. To access the poster click the link on the right. To read the full paper click here

Presented on Wednesday 18 May: Session 17 NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland. To access the presentation click the link on the right. To read the full paper click here

There is, in our sense of place, little cognisance of what lies underground. Yet our sense of place, instinctive, unconscious, primeval, has its own underground: the secret spaces which mirror our insides; the world beneath the skin. Our roots lie beneath the ground, with the minerals and the dead. (Hughes 83) The-Home-and-Away-Game Imagine the earth-grounded, “diagrammatological” trajectory of a footballer who as one member of a team is psyching himself up before the start of a game. The siren blasts its trumpet call. The footballer bursts out of the pavilion (where this psyching up has taken place) to engage in the opening bounce or kick of the game. And then: running, leaping, limping after injury, marking, sliding, kicking, and possibly even passing out from concussion. Finally, the elation accompanying the final siren, after which hugs, handshakes and raised fists conclude the actual match on the football oval. This exit from the pavilion, the course the player takes during the game itself, and return to the pavilion, forms a combination of stasis and movement, and a return to exhausted stasis again, that every player engages with regardless of the game code. Examined from a “diagrammatological” perspective, a perspective Rowan Wilken (following in the path of Gilles Deleuze and W. J. T. Mitchell) understands as “a generative process: a ‘metaphor’ or way of thinking — diagrammatic, diagrammatological thinking — which in turn, is linked to poetic thinking” (48), this footballer’s scenario arises out of an aerial perspective that depicts the actual spatial trajectory the player takes during the course of a game. It is a diagram that is digitally encoded via a sensor on the footballer’s body, and being an electronically encoded diagram it can also make available multiple sets of data such as speed, heartbeat, blood pressure, maybe even brain-wave patterns. From this limited point of view there is only one footballer’s playing trajectory to consider; various groupings within the team, the whole team itself, and the diagrammatological depiction of its games with various other teams might also be possible. This singular imagining though is itself an actuality: as a diagram it is encoded as a graphic image by a satellite hovering around the earth with a Global Positioning System (GPS) reading the sensor attached to the footballer which then digitally encodes this diagrammatological trajectory for appraisal later by the player, coach, team and management. In one respect, this practice is another example of a willing self-surveillance critical to explaining the reflexive subject and its attribute of continuous self-improvement. According to Docker, Official Magazine of the Fremantle Football Club, this is a technique the club uses as a part of game/play assessment, a system that can provide a “running map” for each player equipped with such a tracking device during a game. As the Fremantle Club’s Strength and Conditioning Coach Ben Tarbox says of this tactic, “We’re getting a physiological profile that has started to build a really good picture of how individual players react during a game” (21). With a little extra effort (and some sizeable computer processing grunt) this two dimensional linear graphic diagram of a footballer working the football ground could also form the raw material for a three-dimensional animation, maybe a virtual reality game, even a hologram. It could also be used to sideline a non-performing player. Now try another related but different imagining: what if this diagrammatological trajectory could be enlarged a little to include the possibility that this same player’s movements could be mapped out by the idea of home-and-away games; say over the course of a season, maybe even a whole career, for instance? No doubt, a wide range of differing diagrammatological perspectives might suggest themselves. My own particular refinement of this movement/stasis on the footballer’s part suggests my own distinctive comings and goings to and from my own specific piece of home country. And in this incessantly domestic/real world reciprocity, in this diurnally repetitive leaving and coming back to home country, might it be plausible to think of “Home as Capital of the Region”? If, as Walter Benjamin suggests in the prelude to his monumental Arcades Project, “Paris — the Capital of the Nineteenth Century,” could it be that both in and through my comings and goings to and from this selfsame home country, my own burgeoning sense of regionality is constituted in every minute-by-minutiae of lived experience? Could it be that this feeling about home is manifested in my every day-to-night manoeuvre of home-and-away-and-away-and-home-making, of every singular instance of exit, play/engage, and the return home? “Home, Capital of the Region” then examines the idea that my home is that part of the country which is the still-point of eternal return, the bedrock to which I retreat after the daily grind, and the point from which I start out and do it all again the next day. It employs, firstly, this ‘diagrammatological’ perspective to illustrate the point that this stasis/movement across country can make an electronic record of my own psychic self-surveillance and actualisation in-situ. And secondly, the architectural plan of the domestic home (examined through the perspective of critical regionalism) is used as a conduit to illustrate how I am physically embedded in country. Lastly, intermingling these digressive threads is chora, Plato’s notion of embodied place and itself an ancient regional rendering of this eternal return to the beginning, the place where the essential diversity of country decisively enters the soul. Chora: Core of Regionality Kevin Lynch writes that, “Our senses are local, while our experience is regional” (10), a combination that suggests this regional emphasis on home-and-away-making might be a useful frame of reference (simultaneously spatiotemporal, both a visceral and encoded communication) for me to include as a crucial vector in my own life-long learning package. Regionality (as, variously, a sub-generic categorisation and an extension/concentration of nationality, as well as a recently re-emerged friend/antagonist to a global understanding) infuses my world of home with a grounded footing in country, one that is a site of an Eternal Return to the Beginning in the micro-world of the everyday. This is a point John Sallis discusses at length in his analysis of Plato’s Timaeus and its founding notion of regionality: chora. More extended absences away from home-base are of course possible but one’s return to home on most days and for most nights is a given of post/modern, maybe even of ancient everyday experience. Even for the continually shifting nomad, nightfall in some part of the country brings the rest and recreation necessary for the next day’s wanderings. This fundamental question of an Eternal Return to the Beginning arises as a crucial element of the method in Plato’s Timaeus, a seemingly “unstructured” mythic/scientific dialogue about the origins and structure of both the psychically and the physically implaced world. In the Timaeus, “incoherence is especially obvious in the way the natural sequence in which a narrative would usually unfold is interrupted by regressions, corrections, repetitions, and abrupt new beginnings” (Gadamer 160). Right in the middle of the Timaeus, in between its sections on the “Work of Reason” and the “Work of Necessity”, sits chora, both an actual spatial and bodily site where my being intersects with my becoming, and where my lived life criss-crosses the various arts necessary to articulating a recorded version of that life. Every home is a grounded chora-logical timespace harness guiding its occupant’s thoughts, feelings and actions. My own regionally implaced chora (an example of which is the diagrammatological trajectory already outlined above as my various everyday comings and goings, of me acting in and projecting myself into context) could in part be understood as a graphical realisation of the extent of my movements and stationary rests in my own particular timespace trajectory. The shorthand for this process is ‘embedded’. Gregory Ulmer writes of chora that, “While chorography as a term is close to choreography, it duplicates a term that already exists in the discipline of geography, thus establishing a valuable resonance for a rhetoric of invention concerned with the history of ‘place’ in relation to memory” (Heuretics 39, original italics). Chorography is the geographic discipline for the systematic study and analysis of regions. Chora, home, country and regionality thus form an important multi-dimensional zone of interplay in memorialising the game of everyday life. In light of these observations I might even go so far as to suggest that this diagrammatological trajectory (being both digital and GPS originated) is part of the increasingly electrate condition that guides the production of knowledge in any global/regional context. This last point is a contextual connection usefully examined in Alan J. Scott’s Regions and the World Economy: The Coming Shape of Global Production, Competition, and Political Order and Michael Storper’s The Regional World: Territorial Development in a Global Economy. Their analyses explicitly suggest that the symbiosis between globalisation and regionalisation has been gathering pace since at least the end of World War Two and the Bretton Woods agreement. Our emerging understanding of electracy also happens to be Gregory Ulmer’s part-remedy for shifting the ground under the intense debates surrounding il/literacy in the current era (see, in particular, Internet Invention). And, for Tony Bennett, Michael Emmison and John Frow’s analysis of “Australian Everyday Cultures” (“Media Culture and the Home” 57–86), it is within the home that our un.conscious understanding of electronic media is at its most intense, a pattern that emerges in the longer term through receiving telegrams, compiling photo albums, listening to the radio, home- and video-movies, watching the evening news on television, and logging onto the computer in the home-office, media-room or home-studio. These various generalisations (along with this diagrammatological view of my comings and goings to and from the built space of home), all point indiscriminately to a productive confusion surrounding the sedentary and nomadic opposition/conjunction. If natural spaces are constituted in nouns like oceans, forests, plains, grasslands, steppes, deserts, rivers, tidal interstices, farmland etc. (and each categorisation here relies on the others for its existence and demarcation) then built space is often seen as constituting its human sedentary equivalent. For Deleuze and Guatteri (in A Thousand Plateaus, “1227: Treatise on Nomadology — The War Machine”) these natural spaces help instigate a nomadic movement across localities and regions. From a nomadology perspective, these smooth spaces unsettle a scientific, numerical calculation, sometimes even aesthetic demarcation and order. If they are marked at all, it is by heterogenous and differential forces, energised through constantly oscillating intensities. A Thousand Plateaus is careful though not to elevate these smooth nomadic spaces over the more sedentary spaces of culture and power (372–373). Nonetheless, as Edward S. Casey warns, “In their insistence on becoming and movement, however, the authors of A Thousand Plateaus overlook the placial potential of settled dwelling — of […] ‘built places’” (309, original italics). Sedentary, settled dwelling centred on home country may have a crust of easy legibility and order about it but it also formats a locally/regionally specific nomadic quality, a point underscored above in the diagrammatological perspective. The sedentary tendency also emerges once again in relation to home in the architectural drafting of the domestic domicile. The Real Estate Revolution When Captain Cook planted the British flag in the sand at Botany Bay in 1770 and declared the country it spiked as Crown Land and henceforth will come under the ownership of an English sovereign, it was also the moment when white Australia’s current fascination with real estate was conceived. In the wake of this spiking came the intense anxiety over Native Title that surfaced in late twentieth century Australia when claims of Indigenous land grabs would repossess suburban homes. While easily dismissed as hyperbole, a rhetorical gesture intended to arouse this very anxiety, its emergence is nonetheless an indication of the potential for political and psychic unsettling at the heart of the ownership and control of built place, or ‘settled dwelling’ in the Australian context. And here it would be wise to include not just the gridded, architectural quality of home-building and home-making, but also the home as the site of the family romance, another source of unsettling as much as a peaceful calming. Spreading out from the boundaries of the home are the built spaces of fences, bridges, roads, railways, airport terminals (along with their interconnecting pathways), which of course brings us back to the communications infrastructure which have so often followed alongside the development of transport infrastructure. These and other elements represent this conglomerate of built space, possibly the most significant transformation of natural space that humanity has brought about. For the purposes of this meditation though it is the more personal aspect of built space — my home and regional embeddedness, along with their connections into the global electrosphere — that constitutes the primary concern here. For a sedentary, striated space to settle into an unchallenged existence though requires a repression of the highest order, primarily because of the home’s proximity to everyday life, of the latter’s now fading ability to sometimes leave its presuppositions well enough alone. In settled, regionally experienced space, repressions are more difficult to abstract away, they are lived with on a daily basis, which also helps to explain the extra intensity brought to their sometimes-unsettling quality. Inversely, and encased in this globalised electro-spherical ambience, home cannot merely be a place where one dwells within avoiding those presuppositions, I take them with me when I travel and they come back with me from afar. This is a point obliquely reflected in Pico Iyer’s comment that “Australians have so flexible a sense of home, perhaps, that they can make themselves at home anywhere” (185). While our sense of home may well be, according to J. Douglas Porteous, “the territorial core” of our being, when other arrangements of space and knowledge shift it must inevitably do so as well. In these shifts of spatial affiliation (aided and abetted by regionalisation, globalisation and electronic knowledge), the built place of home can no longer be considered exclusively under the illusion of an autonomous sanctuary wholly guaranteed by capitalist property relations, one of the key factors in its attraction. These shifts in the cultural, economic and psychic relation of home to country are important to a sense of local and regional implacement. The “feeling” of autonomy and security involved in home occupation and/or ownership designates a component of this implacement, a point leading to Eric Leed’s comment that, “By the sixteenth century, literacy had become one of the definitive signs — along with the possession of property and a permanent residence — of an independent social status” (53). Globalising and regionalising forces make this feeling of autonomy and security dynamic, shifting the ground of home, work-place practices and citizenship allegiances in the process. Gathering these wide-ranging forces impacting on psychic and built space together is the emergence of critical regionalism as a branch of architectonics, considered here as a theory of domestic architecture. Critical Regionality Critical regionalism emerged out of the collective thinking of Liane Lefaivre and Alexander Tzonis (Tropical Architecture; Critical Regionalism), and as these authors themselves acknowledge, was itself deeply influenced by the work of Lewis Mumford during the first part of the twentieth century when he was arguing against the authority of the international style in architecture, a style epitomised by the Bauhaus movement. It is Kenneth Frampton’s essay, “Towards a Critical Regionalism: Six Points for an Architecture of Resistance” that deliberately takes this question of critical regionalism and makes it a part of a domestic architectonic project. In many ways the ideas critical regionalism espouses can themselves be a microcosm of this concomitantly emerging global/regional polis. With public examples of built-form the power of the centre is on display by virtue of a building’s enormous size and frequently high-cultural aesthetic power. This is a fact restated again and again from the ancient world’s agora to Australia’s own political bunker — its Houses of Parliament in Canberra. While Frampton discusses a range of aspects dealing with the universal/implaced axis across his discussion, it is points five and six that deserve attention from a domestically implaced perspective. Under the sub-heading, “Culture Versus Nature: Topography, Context, Climate, Light and Tectonic Form” is where he writes that, Here again, one touches in concrete terms this fundamental opposition between universal civilization and autochthonous culture. The bulldozing of an irregular topography into a flat site is clearly a technocratic gesture which aspires to a condition of absolute placelessness, whereas the terracing of the same site to receive the stepped form of a building is an engagement in the act of “cultivating” the site. (26, original italics) The “totally flat datum” that the universalising tendency sometimes presupposes is, within the critical regionalist perspective, an erroneous assumption. The “cultivation” of a site for the design of a building illustrates the point that built space emerges out of an interaction between parallel phenomena as they contrast and/or converge in a particular set of timespace co-ordinates. These are phenomena that could include (but are not limited to) geomorphic data like soil and rock formations, seismic activity, inclination and declension; climatic considerations in the form of wind patterns, temperature variations, rainfall patterns, available light and dark, humidity and the like; the building context in relation to the cardinal points of north, south, east, and west, along with their intermediary positions. There are also architectural considerations in the form of available building materials and personnel to consider. The social, psychological and cultural requirements of the building’s prospective in-dwellers are intermingled with all these phenomena. This is not so much a question of where to place the air conditioning system but the actuality of the way the building itself is placed on its site, or indeed if that site should be built on at all. A critical regionalist building practice, then, is autochthonous to the degree that a full consideration of this wide range of in-situ interactions is taken into consideration in the development of its design plan. And given this autochthonous quality of the critical regionalist project, it also suggests that the architectural design plan itself (especially when it utilised in conjunction with CAD and virtual reality simulations), might be the better model for designing electrate-centred projects rather than writing or even the script. The proliferation of ‘McMansions’ across many Australian suburbs during the 1990s (generally, oversized domestic buildings designed in the abstract with little or no thought to the above mentioned elements, on bulldozed sites, with powerful air-conditioning systems, and no verandas or roof eves to speak of) demonstrates the continuing influence of a universal, centralising dogma in the realm of built place. As summer temperatures start to climb into the 40°C range all these air-conditioners start to hum in unison, which in turn raises the susceptibility of the supporting infrastructure to collapse under the weight of an overbearing electrical load. The McMansion is a clear example of a built form that is envisioned more so in a drafting room, a space where the architect is remote-sensing the locational specificities. In this envisioning (driven more by a direct line-of-sight idiom dominant in “flat datum” and economic considerations rather than architectural or experiential ones), the tactile is subordinated, which is the subject of Frampton’s sixth point: It is symptomatic of the priority given to sight that we find it necessary to remind ourselves that the tactile is an important dimension in the perception of built form. One has in mind a whole range of complementary sensory perceptions which are registered by the labile body: the intensity of light, darkness, heat and cold; the feeling of humidity; the aroma of material; the almost palpable presence of masonry as the body senses it own confinement; the momentum of an induced gait and the relative inertia of the body as it traverses the floor; the echoing resonance of our own footfall. (28) The point here is clear: in its wider recognition of, and the foregrounding of my body’s full range of sensate capacities in relation to both natural and built space, the critical regionalist approach to built form spreads its meaning-making capacities across a broader range of knowledge modalities. This tactility is further elaborated in more thoroughly personal ways by Margaret Morse in her illuminating essay, “Home: Smell, Taste, Posture, Gleam”. Paradoxically, this synaesthetic, syncretic approach to bodily meaning-making in a built place, regional milieu intensely concentrates the site-centred locus of everyday life, while simultaneously, the electronic knowledge that increasingly underpins it expands both my body’s and its region’s knowledge-making possibilities into a global gestalt, sometimes even a cosmological one. It is a paradoxical transformation that makes us look anew at social, cultural and political givens, even objective and empirical understandings, especially as they are articulated through national frames of reference. Domestic built space then is a kind of micro-version of the multi-function polis where work, pleasure, family, rest, public display and privacy intermingle. So in both this reduction and expansion in the constitution of domestic home life, one that increasingly represents the location of the production of knowledge, built place represents a concentration of energy that forces us to re-imagine border-making, order, and the dynamic interplay of nomadic movement and sedentary return, a point that echoes Nicolas Rothwell’s comment that “every exile has in it a homecoming” (80). Albeit, this is a knowledge-making milieu with an expanded range of modalities incorporated and expressed through a wide range of bodily intensities not simply cognitive ones. Much of the ambiguous discontent manifested in McMansion style domiciles across many Western countries might be traced to the fact that their occupants have had little or no say in the way those domiciles have been designed and/or constructed. In Heidegger’s terms, they have not thought deeply enough about “dwelling” in that building, although with the advent of the media room the question of whether a “building” securely borders both “dwelling” and “thinking” is now open to question. As anxieties over border-making at all scales intensifies, the complexities and un/sureties of natural and built space take ever greater hold of the psyche, sometimes through the advance of a “high level of critical self-consciousness”, a process Frampton describes as a “double mediation” of world culture and local conditions (21). Nearly all commentators warn of a nostalgic, romantic or a sentimental regionalism, the sum total of which is aimed at privileging the local/regional and is sometimes utilised as a means of excluding the global or universal, sometimes even the national (Berry 67). Critical regionalism is itself a mediating factor between these dispositions, working its methods and practices through my own psyche into the local, the regional, the national and the global, rejecting and/or accepting elements of these domains, as my own specific context, in its multiplicity, demands it. If the politico-economic and cultural dimensions of this global/regional world have tended to undermine the process of border-making across a range of scales, we can see in domestic forms of built place the intense residue of both their continuing importance and an increased dependency on this electro-mediated world. This is especially apparent in those domiciles whose media rooms (with their satellite dishes, telephone lines, computers, television sets, games consuls, and music stereos) are connecting them to it in virtuality if not in reality. Indeed, the thought emerges (once again keeping in mind Eric Leed’s remark on the literate-configured sense of autonomy that is further enhanced by a separate physical address and residence) that the intense importance attached to domestically orientated built place by globally/regionally orientated peoples will figure as possibly the most viable means via which this sense of autonomy will transfer to electronic forms of knowledge. If, however, this here domestic habitué turns his gaze away from the screen that transports me into this global/regional milieu and I focus my attention on the physicality of the building in which I dwell, I once again stand in the presence of another beginning. This other beginning is framed diagrammatologically by the building’s architectural plans (usually conceived in either an in-situ, autochthonous, or a universal manner), and is a graphical conception that anchors my body in country long after the architects and builders have packed up their tools and left. This is so regardless of whether a home is built, bought, rented or squatted in. Ihab Hassan writes that, “Home is not where one is pushed into the light, but where one gathers it into oneself to become light” (417), an aphorism that might be rephrased as follows: “Home is not where one is pushed into the country, but where one gathers it into oneself to become country.” For the in-and-out-and-around-and-about domestic dweller of the twenty-first century, then, home is where both regional and global forms of country decisively enter the soul via the conduits of the virtuality of digital flows and the reality of architectural footings. 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