Showing papers in "The APPEA Journal in 1989"
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TL;DR: The region of the North West Shelf dealt with in this paper is underlain by three of the four basins which make up the Westralian Superbasin this paper.
Abstract: The region of the North West Shelf dealt with in this paper is underlain by three of the four basins which make up the Westralian Superbasin The Bonaparte Basin lies outside the scope of this paper; the other basins are the Browse Basin, the offshore Canning Basin, here named the Western Canning Basin, and the offshore Carnarvon Basin, here called the Northern Carnarvon Basin Sediments belonging to ten depositional sequences (Pz5, Mzl to Mz5, and Czl to Cz4) are present in the basins, the oldest being of Late Carboniferous and Permian age (Pz5) Deposition commenced in rift (interior fracture) basins under fluvial/deltaic conditions in the Late Permian/Early Triassic (Mzl), when the North West Shelf was part of Gondwana Continental breakup took place in the Middle Jurassic (breakup unconformity between Mz2 and Mz3), and marine conditions prevailed over the Westralian Superbasin thereafter, with deposition taking place in a marginal sag setting Siliciclastic sediments gave place to carbonates in the Late Cretaceous (Mz5) as the Indian Ocean grew larger Parts of the area have been under permit since 1946, and to date some 227 exploration wells have been drilled The most intensive exploration has taken place in the Northern Carnarvon Basin (191 wells), followed by the Browse Basin (20 wells), and Western Canning Basin (16 wells) Thirty- four economic and potentially economic discoveries have been made The main target reservoirs are Triassic, Jurassic and Cretaceous, and the regional seals are Triassic and Cretaceous The fields are of two types: pre- breakup unconformity (mainly tilted horst blocks), and post- breakup unconformity (usually four- way dip closures) Of the five producing fields, the North Rankin Gas Field is a pre- breakup field, while the four oil fields (Barrow, Harriet, South Pepper and North Herald) are all post- breakup
32 citations
TL;DR: The potential for an additional 16 × 109 m3 of gas and 2 × 106 ML of oil reserves to be found in the Bowen and overlying Surat Basins is discussed in this paper.
Abstract: Exploration for petroleum in Queensland began in the Bowen and overlying Surat Basins in 1908. During the next 50 years a few small fields were found. The discovery of oil at Moonie in 1961 and a number of gas fields on the Roma Shelf during the 1960s triggered extensive seismic and drilling programs. This resulted in additional discoveries and the construction of an oil pipeline to Brisbane in 1964 and a gas pipeline in 1969. To date more than 680 exploration and 350 appraisal wells have been drilled. Approximately 16 × 109 m3 of gas and 5 × 106 ML of oil have been discovered. There is potential for an additional 16 × 109 m3 of gas and 2 × 106 ML of oil reserves to be found in the basins. There is a much greater risk in finding the oil reserves than the gas reserves. The oil and gas reserves occur within Permian, Triassic and Jurassic sandstone reservoirs.
25 citations
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TL;DR: The Otway Basin is structurally complex as a result of the superposition of a number of tectonic events which occurred both during and after the development of the basin this paper.
Abstract: The Otway Basin covers an area of some 150 000 km2 both onshore and offshore southwestern Victoria and southeastern South Australia. Exploration within the basin is at a moderately mature stage by Australian standards (though immature by world standards), with a well density of one per 1500 km2, including offshore areas. Formation of the Otway Basin commenced in the late Jurassic with the initiation of rifting between Australia and Antarctica. As rifting continued, a number of depositional cycles occurred. Initial deposition comprised fluvio- lacustrine sediments, followed by marine transgressions and associated regressive deltaic cycles. As subsidence continued into the Late Tertiary, a series of marine carbonates and marls were deposited. The Otway Basin is structurally complex as a result of the superposition of a number of tectonic events which occurred both during and after the development of the basin. The Otway Basin is a proven gas province, with commercial production at Caroline 1 (carbon dioxide) and North Paaratte Field (methane). Although no commercial oil production has yet been established in the basin, oil has been recovered at Port Campbell 4, Lindon 1 and Windermere 1. The presence of excellent reservoir units within the basin, mature source rocks and adequate seals, together with a number of untested play types and favourable economics, augurs well for the prospectivity of the Otway Basin.
19 citations
TL;DR: The major tectonic and stratigraphic elements of the offshore North Perth Basin have been delineated from regional BMR multichannel seismic reflection lines, together with industry seismic and well data as mentioned in this paper.
Abstract: The major tectonic and stratigraphic elements of the offshore North Perth Basin have been delineated from regional BMR multichannel seismic reflection lines, together with industry seismic and well data. This analysis reveals that three sub- basins, the Edel, Abrolhos and Houtman Sub- basins, have formed as a result of three distinct episodes of rifting within the offshore North Perth Basin during the Early Permian, Late Permian and Late Jurassic respectively. During this period, rifting has propagated from east to west, and has culminated in the separation of this part of the Australian continent from Greater India. The boundaries between the sub- basins and many structures within individual sub- basins are considered to have been produced by strike- slip or oblique- slip motion. The offshore North Perth Basin is believed to be a product of transtension, possibly since the earliest phase of rifting. This has culminated in separation and seafloor spreading by oblique extension along the Wallaby Fracture Zone to form a transform passive continental margin. This style of rifting and extension has produced relatively thin syn- rift sequences, some of which have been either partly or completely removed by erosion. While the source- rock potential of the syn- rift phase is limited, post- rift marine transgressional phases and coal measures do provide adequate and relatively widespread source rocks for hydrocarbon generation. Differences in the timing of rifting across the basin have resulted in a maturation pattern whereby mature sediments become younger to the west.
18 citations
TL;DR: The Cooper Basin is located in the northeastern corner of South Australia and in the southwestern part of Queensland and the first commercial discovery of gas was made at Gidgealpa in 1963 as discussed by the authors.
Abstract: The Cooper Basin is located in the northeastern corner of South Australia and in the southwestern part of Queensland. The basin constitutes an intracratonic depocentre of Permo- Triassic age. The Cooper Basin succession unconformably overlies Proterozoic basement as well as sediments and metasediments of the Cambro- Ordovician age. An unconformity separates in turn the Cooper succession from the overlying Jurassic- Cretaceous Eromanga Basin sediments. The Permo- Triassic succession comprises several cycles of fluvial sandstones, fluvio- deltaic coal measures and lacustrine shales. The coal measures contain abundant humic kerogen, comprising mainly inertinite and vitrinite with a small contribution of exinite. All hydrocarbon accumulations within the Cooper Basin are believed to have originated from these terrestrial source rocks. Exploration of the basin commenced in 1959 and, after several dry holes, the first commercial discovery of gas was made at Gidgealpa in 1963. To date, some 97 gas fields and 10 oil fields, containing recoverable reserves of 5 trillion cubic feet of gas and 300 million barrels recoverable natural gas liquids and oil, have been discovered in the Cooper Basin. Production is obtained from all sand- bearing units within the Cooper stratigraphic succession. The emphasis of exploration in the Cooper Basin is largely directed towards the assessment of four- way dip closures and three- way dip closures with fault control, but several stratigraphic prospects have been drilled. Furthermore, in the development phase of some gas fields a stratigraphic component of the hydrocarbon trapping mechanism has been recognised. Improvements in seismic acquisition and processing, combined with innovative thinking by the explorers, have facilitated the development of untested structural/stratigraphic plays with large reserves potential. Exploration for the four- and three- way dip closure plays in the Cooper Basin is now at a mature stage. However, reserves objectives are expected to continue to be met, with the expectation of a continuing high success rate. Selected new plays are expected to be tested within a continuing active exploration program as exploration for oil and gas in the Cooper Basin refines the search for the subtle trap.
16 citations
TL;DR: With control from only the Jabiru 1A discovery well and a grid of seismic lines 3 km apart, original oil-in-place at Jabiru was estimated by the operator as 620 MMBBL (100 MkL) as discussed by the authors.
Abstract: With control from only the Jabiru 1A discovery well and a grid of seismic lines 3 km apart, original oil- in- place at Jabiru was estimated by the operator as 620 MMBBL (100 MkL) With a 3- D seismic grid and three more wells, the original oil- in- place estimate was reduced to 45 MMBBL (7 MkL) Subsequent drilling of three more wells has enabled this estimate to be increased to about 110 MMBBL (17 MkL) Production from the field is currently at a rate of about 43 000 BOPD (6800 kL/d), from the discovery well and the latter three wells Seismic data across the Jabiru structure is poor and lacks character at the reservoir level, with the result that interpretation is partly dependent on the interpreter's preferred structural model Initially, interpretation of a broad horst, up to 3 km across, seemed appropriate Now most of the oil in the structure is thought to be in a narrow sub- structure, about 500 m wide, believed by some to be a sub- horst The existence of a sub- horst is difficult to justify structurally, and a third possibility, in which the sub- horst was a terrace of a now- inverted graben, is proposed The development of the graben and its subsequent inversion would most likely result from strike- slip and dip- slip motion along an underlying northeast- trending fault The strike- slip is interpreted as right- lateral during the Late Jurassic, and left- lateral during Early Cretaceous and Late Miocene to Holocene Such strike- slip has not previously been recognised in the Jabiru area Consideration of structural models has been useful in predicting the potential of areas of very poor data at Jabiru The concept of balanced sections is helpful in determining the model which best fits the data and is geometrically feasible
14 citations
TL;DR: In this paper, a visual method of estimating permeability was applied by comparison of the drill cores with a standard set of cores of known permeability, made on fresh, dry rock surfaces with the aid of a binocular microscope at 20 × magnification.
Abstract: The Sydney Basin, despite numerous encouraging shows of both free oil and gas from coal and petroleum exploration drilling, remains unproductive of commercial hydrocarbons. Reservoir potential has historically been the primary concern, owing to widespread distribution throughout the sequence of lithic, diagenetically- altered, clay- rich sandstones. This study aimed at defining areas of acceptable reservoir quality by careful examination of stratigraphic, depositional and diagenetic controls. Interpretation and extrapolation of reservoir distribution, attributes and quality were carried out within a genetic stratigraphic framework. Stratigraphic packages of widespread correlatability that were deposited during discrete episodes of basin filling provide the basis for delineation of component depositional systems and for further mapping of framework sandstone facies and associated mud rocks. The availability of numerous, continuous drill cores from existing coal bores and limited petroleum exploration wells provided an opportunity to directly quantify porosity and permeability. A visual method of estimating permeability was applied by comparison of the drill cores with a standard set of cores of known permeability. The comparison was made on fresh, dry rock surfaces with the aid of a binocular microscope at 20 × magnification. Reliability of the visual estimates was then assessed by laboratory measurement of a large representative sample set. Lithofacies maps of genetic stratigraphic packages define sand- body trends and allow interpretative extrapolation of reservoir facies tracts which, when integrated with the visually- estimated and laboratory- derived reservoir quality data, enabled mapping of regional permeability distribution and thickness. The principal conclusions of the study are that reservoirs with sufficient porosity, permeability and volume for conventional oil and gas production exist within the Sydney Basin. Best reservoir quality occurs in quartzose sandstones of the Narrabeen Group in the southwestern part of the basin. Potential reservoir sandstones are up to 20 m thick, have permeabilities in the 10- 1000 md range and porosity between 10 and 18 per cent. Calibration and testing of the visual estimation technique allowed accurate and efficient continuous recording and mapping of porosity and permeability, and this technique may have much wider application for the petroleum industry.
14 citations
TL;DR: The Upper Waarre Formation can be subdivided into four units, identified as Unit A, a basal fining upward sequence; Unit B, a medial siltstone with interbedded calcareous sandstones; Unit C, a coarse-grained porous sandstone (the primary gas reservoir); Unit D, a ferruginous siltstones/sandstone sequence.
Abstract: The Late Cretaceous Waarre Formation is recognised as the principal reservoir unit throughout the Port Campbell Embayment, where a number of small gas fields were discovered and developed in the late 1970s and the early and mid- 1980s. The Waarre Formation can be subdivided into four units, identified as Unit A, a basal fining upward sequence; Unit B, a medial siltstone with interbedded calcareous sandstones; Unit C, a coarse- grained porous sandstone (the primary gas reservoir); Unit D, a ferruginous siltstone/sandstone sequence. The Upper Waarre, Units C and D, represents a variety of environments unique to a beach barrier- system, including back- water lagoons, swamps, tidal channels, tidal deltas, and beach sands. The development of an Upper Waarre sandstone- beach- barrier model, the identification of various facies, and the construction of regional palaeogeography leads to an understanding of sedimentary deposition during Waarre times. Recent drilling has shown the Upper Waarre to extend laterally in an easterly direction and, as proposed by the depositional model, development of the prospective Waarre Unit C gas sands in a restricted linear east- west zone. By combining the complex structural history of the Port Campbell Embayment and the resultant structures developed with the depositional model of the Waarre Formation, major migration pathways, and thick (>50 m) overlying seals, exploration throughout the embayment can be directed towards prospective gas reservoirs within the Waarre, Unit C, sandstone bodies.
14 citations
TL;DR: In this article, an exploration strategy was developed to assess, in the most cost effective manner, the principal uncertainties associated with the play over a two-year period, and a drilling program of six 500 m coreholes, each overlapping slightly in terms of stratigraphy, was sited along one of Shell's seismic lines.
Abstract: Shell was attracted to the potential of the northern Drummond Basin by large anticlinal structures, already evident from patchy outcrop and limited seismic data. An exploration strategy was developed to assess, in the most cost effective manner, the principal uncertainties associated with the play over a two- year period. Initially a regional seismic program of 270 km was acquired. This provided sub- surface control essential for the subsequent corehole drilling program, and an outline of the regional structural framework. The drilling program of six 500 m coreholes, each overlapping slightly in terms of stratigraphy, was sited along one of Shell's seismic lines. A total of 2569 m of core was recovered, providing 2083 m of true stratigraphic coverage, thus facilitating detailed stratigraphic, reservoir, seal and geochemical studies. The new seismic data have led to a revision of the tectonic model of the basin, which, despite a complex uplift history, remains at maturity levels compatible with hydrocarbon occurrence. Core studies have highlighted the major exploration risks as relatively poor reservoir quality, limited source- rock development and thin intra- formational seals. Despite the disappointing outcome in terms of hydrocarbon prospectivity, significant advances have been made in the understanding of the geology of central Queensland, particularly relating to tectonics and burial history, which may be of regional significance.
11 citations
TL;DR: In this article, an investigation has been made of the source potential, degree of maturation and hydrocarbon composition of selected oils and sediments in the Murta Member in ATP 267P and the Moomba and Napacoongee-Murteree Blocks (PEL 5 and 6), Eromanga Basin.
Abstract: An investigation has been made of the source potential, degree of maturation and hydrocarbon composition of selected oils and sediments in the Murta Member in ATP 267P and the Moomba and Napacoongee- Murteree Blocks (PEL 5 and 6), Eromanga Basin. Shales in the Murta Member contain low amounts (up to 2.5% TOC) of terrestrial oil- prone organic matter (Types II–III) which consists predominantly of sporinite, lipto- detrinite and inertinite with lower amounts of vitrinite, although some samples contain relatively abundant telalginite. Extractable hydrocarbon yields demonstrate that parts of the Murta Member are effective source rocks at present maturation levels, which are at the threshold of the conventional oil window (vitrinite reflectance = 0.5- 0.6% Ro). Oils from Murta reservoirs in ATP 267P (Kihee, Nockatunga and Thungo) all show the characteristics found by previous analyses of many Murta oils, namely paraffinic, low wax, and high pristane- to- phytane ratios. In contrast Murta oils from Limestone Creek and Biala are waxy. All oils show chemical evidence of generation at relatively low maturation levels. Gas chromatograms of the saturate fractions from the best source facies show the same characteristics noted for the low- wax oils. Samples with lower source potential in contrast contain relatively abundant waxy n- alkanes. Methylphenan- threne Indices and biomarker maturation indicators obtained from the oils show the same values as were measured on sediment samples from the Murta. Hence the oils could not have been derived from deeper, more mature source rocks. The distribution of biomarkers in the low- wax oils is also consistent with an origin from the Murta Member. A corresponding source facies for the high- wax oils has not yet been located. However, chemical maturation indices also suggest a source in the Murta Member or in immediately adjacent strata. The unusual circumstances represented by the Murta oils (low maturity, low- wax terrestrial oils) provide evidence for bacterial contribution to the source material for non- marine oils. Both the low- wax oils and the best source facies contain abundant hydrocarbons derived from bacterial precursors. This bacterial organic matter appears to yield hydrocarbons at an earlier stage of maturation than the predominantly terrestrial plant and algal organic matter with which it is associated. In the case of the Murta Member there are sufficient hydrocarbons generated at relatively low maturity to allow migration to occur. Chemical evidence suggests a low contribution from algal organic matter to the generated hydrocarbons.
11 citations
TL;DR: In the Canning Basin this article, the majority of wildcat reports are associated with reports of petroleum shows, and there are seven different formations and three distinctive trap types: draped bioherms, anticlinal culminations and tilted horsts.
Abstract: The prospectivity of the Canning Basin is by no means exhausted. Furthermore, low product prices will offer those with the will and the wherewithal some relatively low cost opportunities to drill seismically well- defined, selected plays in selected acreage. There may never be a better time to invest in the Canning Basin. The Canning Basin rock record includes at least 16 distinct regional episodes of onlapping, quiet- water conditions that transgressed higher energy reservoir- type facies. These vertical successions often constitute correctable seismic sequences and represent apt horizons at which to map prospective, shale- capped trap configurations. All of these 16+ top- sealed reservoir levels are associated with oil and/or gas shows in some part of the Canning Basin. Indeed, the majority of Canning Basin wildcats are associated with reports of petroleum shows. There are seven separate petroleum discoveries (four developed) in the Canning Basin. These span seven different formations and three distinctive trap- types: draped bioherms, anticlinal culminations and tilted horsts. While the overall historical ratio of discoveries to wildcats is low (~1:19), the most successful joint venture in the Canning Basin can claim a 1 in 5.3 rate of discovery leading to development since its first wildcat (Blina 1) in 1980. The most effective oil source rocks in the Canning Basin are thought to be Arenigian to Llanvirnian (Ordovician) marine shales, the Givetian to Frasnian (Devonian) Gogo Formation and the Late Devonian to Early Carboniferous Fairfield Group, in particular the Tournaisian Laurel Formation. The most consistently permeable reservoirs that are most frequently in favourable juxtaposition to source rocks and seals are the Permo- Carboniferous glacigenic quartzose sandstones of the Grant Group. Most other Palaeozoic reservoirs that are judged to have adequate top seals are less regularly porous. All significant porosity in carbonates in the Canning Basin is apparently diagenetic and irregularly distributed. Those carbonates most likely to be permeable are leached and/or dolomitised and/or fractured. Regressive carbonates, carbonates interfingering with permeable siliciclastics, carbonates adjacent to major faults, and carbonates that either lie above or are cut by unconformities are those apparently most frequently dolomitised. Fenestrate (especially algal) and oolitic fabrics provide excellent habitats for high levels of secondary dolomite and subsequently leached porosity. The Nita, Mellinjerie (lowermost Pillara), uppermost Nullara and Yellow Drum Formations are those units that most frequently exhibit these characteristics in the Canning Basin. Reefs, salt domes and anticlines have enticed, and will probably continue to attract, explorers to the Canning Basin. Traps including (1) intra- Grant Group palaeo- monadnocks, (2) Carribuddy salt pillows and salt evacuation- related turtle- backs, (3) low- stand submarine fan sandstone complexes in the Frasnian Gogo Formation and (4) tilted horsts at Ordovician levels are additional recognised play types that warrant continued interest and will probably be further explored, if product prices permit.
TL;DR: The Gippsland Basin is, by Australian standards, mature from a petroleum exploration point of view but retains significant potential for success as mentioned in this paper, with the main recognised plays of Top Latrobe porosity, deeper fault blocks and stratigraphic truncations, with the latter two showing the greater undiscovered potential.
Abstract: The Gippsland Basin is, by Australian standards, mature from a petroleum exploration point of view but retains significant potential for success. The main recognised plays of Top Latrobe porosity, deeper fault blocks and stratigraphic truncations are in various stages of exploitation, with the latter two showing the greater undiscovered potential. Parameters for hydrocarbon accumulations, such as source, seal, structural style and trap timing, are now reasonably well documented and future success in established and untested plays will rely heavily on detailed velocity analysis, deep- penetration high- frequency seismic data and an integrated regional approach to stratigraphic controls.
TL;DR: The first discovery of Triassic reefal material near the Australian North West Shelf was made by the Ocean Drilling Program (ODP) during Leg 122 in the Exmouth Plateau region, which cored 200 m of Upper Triassic (Rhaetian) reef complex as mentioned in this paper.
Abstract: Site 764 of the Ocean Drilling Program (ODP), drilled during Leg 122 in the Exmouth Plateau region, cored 200 m of Upper Triassic (Rhaetian) reef complex. This site, on the northern Wombat Plateau (northernmost Exmouth Plateau) represents the first discovery of Triassic reefal material near the Australian North West Shelf. Seismic reflection data through Site 764 show that the reef itself corresponds predominantly to a seismically poorly reflective zone. A number of regional unconformities appear to correspond, however, to traceable seismic horizons which pass with reduced amplitude through the reef, indicating stages of reef growth separated by erosion or non- deposition. Seismic facies around the edges of the reef are consistent with the deposition of wedges of prograding reef- derived detritus. Application of the seismic criteria for reef recognition established at ODP Site 764, to other seismic reflection data on the Wombat Plateau, demonstrates that a major Upper Triassic reef complex fringes the margins of the Wombat Plateau. The Wombat Plateau lies at the western end of the North West Shelf, which was part of the southern margin of a warm Tethys Ocean in the Late Triassic, at a palaeolatitude of 25- 30°S. Upper Triassic reefs are known from southeast Indonesia and Papua New Guinea, and now the Wombat Plateau, and may be common elsewhere along the outer margin of the North West Shelf. Upper Triassic reef complexes, with their associated reservoir, source and seal facies, could represent an exciting new petroleum exploration play for the entire North West Shelf. Facies analysis suggests that they are likely only on the outer shelf and slope. Shallow Triassic reef complexes are clearly identifiable using high resolution seismic reflection data. Seismic reflection data of lower resolution may well reveal the associated detrital carbonate wedges, which are more laterally extensive than the reefal core, deeper in the section.
TL;DR: The Joseph Bonaparte Gulf area of northwestern Australia contains a Devonian-Tertiary depocentre whose origins and subsequent history can be related to an episode of Devonian rifting as mentioned in this paper.
Abstract: The Joseph Bonaparte Gulf area of northwestern Australia contains a Devonian- Tertiary depocentre whose origins and subsequent history can be related to an episode of Devonian rifting. Three decades of petroleum exploration have delineated large offshore gas accumulations. However, despite the apparent existence of all the factors necessary for oil generation and entrapment, only traces of liquid hydrocarbons have been found to date. The location of good- quality sealed reservoirs is the main challenge facing continued oil exploration.
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TL;DR: The Eromanga Basin is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain and overlained by a coal-swamp sequence.
Abstract: The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments. Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain. The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations. All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors. Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas. Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.
TL;DR: 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.
Abstract: 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.
TL;DR: In this paper, the BMR research vessel Rig Seismic carried out a 21-day geochemical and sedimento- logical research program in the Otway and Gippsland Basins.
Abstract: During April- May 1988, the BMR research vessel Rig Seismic carried out a 21- day geochemical and sedimento- logical research program in the Otway (17 days) and Gippsland (4 days) Basins. The concentrations and molecular compositions of light hydrocarbon gases (C1- C4) were measured in sediments at 203 locations on the continental shelf and upper continental slope: the presence of thermogenic hydrocarbons was inferred from the molecular compositions of the gas mixtures. Thermogenic hydrocarbons were identified in near- surface sediments at 32 locations in the Otway Basin; 6 of these locations were on the Crayfish Platform, 7 were on the Mussel Platform and 17 were in the Voluta Trough. Thermogenic hydrocarbons were identified at 10 locations in the Gippsland Basin. Data from the Otway Basin indicated that total C1- C4 gas concentrations were higher in the Voluta Trough than on the basin margins, probably because intense faulting in the trough facilitates gas migration from deeply buried source rocks and/or reservoirs to the seafloor. However, anomalies were detected where the Tertiary sequence was thick and relatively unfaulted. The wet gas contents of the anomalies were highest on the basin margins, lower in the Voluta Trough and co- varied with the depth of burial of the basal Early Cretaceous sedimentary sequence. These data, when integrated with geohistory, thermal maturation modelling and well data, suggest that the areas with the best potential for liquid hydrocarbon entrapment and preservation are the Crayfish Platform and the inshore part of the Mussel Platform. In contrast, the Late Cretaceous Sherbrook Group and much of the Voluta Trough appear to be gas prone. Thermogenic anomalies in the Gippsland Basin were concentrated within and along the margins of the Central Deep where mature Latrobe Group source rocks are present. The wet gas content of these anomalies was variable, which is consistent with the spatial heterogeneity of hydrocarbon accumulations in the Gippsland Basin.
TL;DR: In this article, an integrated sedimentological study utilising core analysis, log analysis, palynology, coal maceral studies and geochemistry, together with sequence stratigraphy, has been used to determine Eocene sedimentation styles in the Bass Basin.
Abstract: The Eocene section in the Bass Basin comprises the upper part of the siliciclastic coal- bearing Eastern View Group and the thin but regionally extensive Demons Bluff Formation. An integrated sedimentological study utilising core analysis, log analysis, palynology, coal maceral studies and geochemistry, together with sequence stratigraphy, has been used to determine Eocene sedimentation styles in the basin. The most likely environment during deposition of the Upper Eastern View Group was a tide- dominated delta consisting of a complex mixture of distributary channels, strandline sand bars, peat swamps and shallow lagoons, the sedimentary successions resulting from a complex interplay between sea- level, tectonics and sediment supply. A major coal- forming episode occurring in the interval 48- 51.5 m.y. is related to oscillations of sea- level following a major highstand. A locally developed progradational unit, Konkon Sandstone, comprising two sandy parasequences separated by a very thin shaly interval is recognised at the top of the Eastern View Group in the northwestern sector of the basin and reaches a maximum thickness of 140 m. The Demons Bluff Formation is a diachronous unit consisting dominantly of siltstone probably deposited in a barred basin with anaerobic conditions.
TL;DR: A review of the available literature shows the environmental effects of seismic surveys to be of little consequence provided non-explosive energy sources are used as mentioned in this paper, however, the potential lethal effects are largely dependent on direct exposure and this declines with the weathering and degradation of the spill.
Abstract: A proposal to undertake exploration in the coastal waters adjacent to Sydney/Newcastle/Wollongong has brought strong protests on environmental grounds. This opposition is committed and the basis for it should be considered in the wider context of offshore exploration around Australia. Of the various activities involved in oil and gas exploration the potential impacts of marine seismic surveys and the likelihood of a blowout- related oil spill are those of greatest concern to the media and public. A review of the available literature shows the environmental effects of seismic surveys to be of little consequence provided non- explosive energy sources are used. The effects of an oil spill are heavily dependent on site conditions and the type of oil spilled. The literature shows that direct exposure to spilled oil is fatal to many marine species. However, the potential lethal effects are largely dependent on direct exposure and this declines with the weathering and degradation of the spill. Moreover, the risks of an oil spill occurring as a result of current transportation and handling of oil in coastal waters and points around Australia are much greater than would be presented by drilling an exploratory well. In considering the role of exploration as an assessment procedure rather than a land use it is possible to draw parallels between the conservation status of Australian coastal waters today and the onshore situation some 20 years ago. The offshore oil and gas exploration industry needs to take several measures if it is to avoid denial of access for exploration. These include clearly identifying the environmental effects of exploration as opposed to production, adopting industry- wide codes for environmental practice, and recording and disseminating the industry's environmental performance.
TL;DR: The Timor Sea, comprising the Territory of Ashmore and Cartier Islands and adjacent waters, is emerging as a major Australian oil- producing area which will contribute significantly to the national economy and Australia's oil self- sufficiency in the 1990s as discussed by the authors.
Abstract: The Timor Sea, comprising the Territory of Ashmore and Cartier Islands and adjacent waters, is emerging as a major Australian oil- producing area which will contribute significantly to the national economy and Australia's oil self- sufficiency in the 1990s. From the Jabiru field alone, Timor Sea oil production contributes 9 per cent of Australia's oil production. The Timor Sea will soon rank second only to Bass Strait in terms of daily production from any one area. If success rates are maintained, Timor Sea could be producing 200 000 BOPD (32 000 kL/d) by the mid- 1990s. Early phases of exploration in the area focused on the detection and drilling of large structures. Success rates were low, mainly because of poor quality seismic data which hindered structural definition and lack of geological understanding as to the controls of hydrocarbon accumulations. Since the Jabiru discovery in 1983, better exploration methods have resulted in the delineation of many prospects which could contain significant oil reserves. New play concepts being developed will result in additional prospects. Economic forecasting and modelling are key factors in determining exploration and development project viability in the area, owing to the wide range in size of the prospects and discoveries. Assuming current economic factors remain in place, modelling indicates that field sizes likely to be found in the Timor Sea will be commercial.
TL;DR: In the Palm Valley Gas Field, central Australia, a 6 km long by 1.5 km wide colour anomaly was detected by the Landsat Thematic Mapper (TM) as discussed by the authors.
Abstract: Digital image processing of advanced aircraft and Landsat Thematic Mapper (TM) satellite remotely sensed data over sandstones of the Palm Valley Gas Field, central Australia, showed a distinct colour anomaly about 6 km long by 1.5 km wide which is not obvious in visible wavelength imagery. Field inspection showed that the colour anomaly was characterised by different rock- weathering colour, a geobotanical anomaly, calcium carbonate precipitation within rock fractures, and different soil pH. Inorganic rock geochemistry indicates significant chemical differences in some major elements. A limited number of soil gas samples were analysed and within the remotely sensed colour anomaly some had above- threshold concentrations of methane, ethane, propane and butane. Preliminary processing of airborne magnetic and gamma spectrometric data over the anticline did not indicate any significant values that suggested abnormal development of magnetite or clay minerals within the colour anomaly. Carbon and oxygen isotope analyses on calcrete from within the colour anomaly suggest, somewhat inconclusively, that hydrocarbons have not contributed significantly to the formation of the calcium carbonate component of the calcrete. Consideration of all available information suggests that the colour anomaly detectable by aircraft and Landsat TM satellite remote sensing corresponds to a zone of surface alteration resulting from long- term seepage of hydrocarbon gases. This colour anomaly, the first of its type reported from Australia, was detected because of spectral reflectance differences resulting from a combination of increased soil carbonate and different geobotanical characteristics from those of the surrounding terrain.
TL;DR: In this paper, an extended test arrangement for the Galoc Field, offshore Philippines, consisted of a semi-submersible drilling rig having a conventional spread mooring to which was connected a storage tanker.
Abstract: The extended test arrangement for the Galoc Field, offshore Philippines, consisted of a semi- submersible drilling rig having a conventional spread mooring to which was connected a storage tanker. The tanker was moored stern to the rig by a disconnectable hawser. At its bow, two anchor lines, also disconnectable, were laid in N/S quadrature symmetrically disposed about the NE/SW tanker orientation. The tanker was thus free to depart from the location, either to discharge its stored oil or to stand by/take cover in the event of heavy weather conditions exceeding the capacity to stay on location. At each lifting, a bottom- hole flowing pressure survey was conducted immediately prior to shut- in. When the well was shut in to disconnect the tanker, the pressure survey incorporated the pressure build- up and subsequently, after reconnection, the pressure drawdown transients. The data batches were collected on digital tapes for analysis. With only three wells in the structure proper, the geological complexity of the reservoir setting did not permit a definitive interpretation of reservoir behaviour during the extended test. However, the use of generic descriptions of submarine fan turbidite deposits, in com- bination with the results obtained from the three wells and history- matching attempts in reproducing the extended test behaviour, did result in a good level of confidence that we had derived an acceptable model of the Galoc Field. The forecast production profiles derived for the various development schemes were thus considered to be reliable enough for comparative economic analyses of the development options.
TL;DR: In this paper, the authors analyse some of the recent legislative developments from the viewpoint of a non-resident investing in Australian petroleum projects, including thin capitalization and debt creation rules for nonresident investors, Australian capital gains tax including the new involuntary roll-over provisions, the Australian dividend imputation system, and secondary taxes such as state royalties and excises and petroleum resource rent tax.
Abstract: Australian legislation has recently undergone further developments which affect non- residents investing in Australian petroleum projects. The comments in this paper reflect our understanding of the law at November 1988. These legislative developments have occurred in foreign investment rules and primary tax areas such as the thin capitalisation and debt creation rules for nonresident investors, Australian capital gains tax including the new involuntary roll- over provisions, the Australian dividend imputation system, and secondary taxes such as state royalties and excises and petroleum resource rent tax. The purpose of this paper is to analyse some of the recent legislative developments from the viewpoint of a non- resident investing in Australian petroleum projects. Changes in most cases are incorporated in complex legislation, and full and proper consideration of the changes is warranted for taxpayers both to comply with the law and maximise shareholders' financial returns.
TL;DR: The costs associated with removal of offshore production facilities can have a serious impact on project economics, especially for the shorter-life marginal fields as mentioned in this paper, and the Australian Government needs to act soon to resolve the issues of residual liability and tax deductibility and so enable the oil industry to select the optimum removal methods and reliably predict future costs for removal.
Abstract: The costs associated with removal of offshore production facilities can have a serious impact on project economics, especially for the shorter- life marginal fields. The requirements for removal of offshore facilities are set out in the Petroleum (Submerged Lands) Act and the guidelines prepared by the International Maritime Organisation, a United Nations agency. Esso Australia Limited has completed a major study of the removal of Bass Strait platforms and has evaluated the costs of platform removal by various methods. Environmental considerations, the needs and safety of other users of the sea, and cost need to be considered when examining options for removal of offshore platforms. The Australian Government needs to act soon to resolve the issues of residual liability and tax deductibility and so enable the oil industry to select the optimum removal methods and reliably predict future costs for removal.
TL;DR: The Saladin Oil Field is located immediately east of Thevenard Island, 25 km northwest of Onslow, in the Barrow Sub-basin, northwest Australia as discussed by the authors.
Abstract: The Saladin Oil Field is located immediately east of Thevenard Island, 25 km northwest of Onslow, in the Barrow Sub- basin, northwest Australia. Saladin 1, drilled in 1985 on a structure mapped from 1984 and older seismic data, tested 47° API oil at 875 kL/d (5510 B/D) from the Early Cretaceous Barrow Group. Additional shallow- water seismic was shot in 1985 and a Telseis* survey conducted in early 1986 over Thevenard Island and its fringing shoals. Saladin 2 in 1986, and Saladin 3 in 1987, tested at 1745 and 1790 kL of oil per day respectively (10 975 and 11 280 BOPD), setting successive Australian single- zone flow records. The fourth well, Saladin 7, was drilled in 1988 on a 1987 seismic line and tested at 1720 kL of oil per day (10 820 BOPD). The oil occurs in southeast- dipping Barrow Group sands overlain by and upthrown against Muderong Shale across the northeast- trending Saladin Fault. The Barrow Group sands have porosities around 24 per cent and permeabilities averaging 5- 6 darcies. Some claystone layers are present, and carbonate cement reduces porosity but less so permeability in parts of the oil column. A bioturbated sand has low permeabilities due to clay burrow- linings. Oil- in- place is currently estimated at 11 MkL (70 MMBBL). Field development will involve offshore platforms and deviated wells from Thevenard Island, on which oil storage and treatment facilities will be placed, and an offshore loading terminal for tanker transport. First oil production is scheduled for mid- 1989.
TL;DR: 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.
Abstract: 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.
TL;DR: The Yolla field, discovered by Amoco, SAGASCO Resources, the Bass Cue Group, Romsey Resources and Southeastern Petroleum in 1985, has sufficient resource potential to support the development of a natural gas supply infrastructure in Tasmania as mentioned in this paper.
Abstract: Tasmania is the only state in Australia which is not supplied with natural gas, and yet a significant gas, condensate and oil resource lies off the Tasmanian coast awaiting development. The Yolla field, discovered by Amoco, SAGASCO Resources, the Bass- Cue Group, Romsey Resources and Southeastern Petroleum in 1985, has sufficient resource potential to support the development of a natural gas supply infrastructure in Tasmania. The field is rich in LPG and condensate and also contains a small oil pool. Tests on the Yolla 1 well were the first in the Bass Basin to flow hydrocarbons and they demonstrated that the field has excellent reservoir properties for commercial development. The keys to the initiation of a gas, condensate and oil development in Tasmania are the need for a significant market for the natural gas and an oil price somewhat better than US$20 per barrel. While there are many major manufacturing and mineral processing plants on the Tasmanian North Coast which would benefit from the stimulus provided by a reliable natural gas pipeline supply, these industries alone provide insufficient load to make an offshore gas development economic. The Bell Bay power station, a thermal power station of 240 MW capacity fired on fuel oil, could, if converted to gas and operated to provide base load supply, generate sufficient base gas demand to enable a project development to proceed. A gas condensate development would provide a substantial stimulus to the Tasmanian economy through:direct investment in the project itself;fostering further development of processing industries on the North Coast;providing cheaper electricity than available from new hydroelectric and coal fired stations;contributing significantly to Tasmanian self- sufficiency in liquid fuels; andreleasing scarce government capital for debt reduction or other uses.
TL;DR: Recon Exploration Pty Ltd is conducting an integrated petroleum exploration program covering the EF-20 Concession using several effective, unconventional methods, including photogeology/geomorphology, remote hydrocarbon sensing and surface geochemical prospecting as discussed by the authors.
Abstract: Recon Exploration Pty Ltd is conducting an integrated petroleum exploration program covering the EF- 20 Concession. It utilises several effective, unconventional methods, including photogeology/geomorphology, remote hydrocarbon sensing and surface geochemical prospecting. The probability of wildcat drilling success is enhanced by several recent developments of prospecting methods being applied in EP20. One of these involves geomorphic detection of diagenetic induration of near- surface sediments over both structural and stratigraphic petroleum- bearing traps believed to be caused by products of bacterial alteration of hydrocarbon micro- seepages. The new giant Alabama Ferry Field strati- graphic trap in Texas showed strong stream drainage deflection anomalies which correlated strongly with the most productive regions of the field. The use of recently available high- resolution Russian satellite photography has disclosed untested similar anomalies in EP20 in the Amadeus Basin. Interstitial soil gas hydrocarbon surveys have been supplemented by simultaneous soil magnetic susceptibility measurements which have been found to complement and fill in some gaps in the soil gas anomalies. At the time of writing, the photogeologic and geomorphic study is complete and it has disclosed many promising areas for further investigation. Of them, 20- 25 per cent have been surveyed using Recon Exploration's helicopter- borne microwave spectrometer hydrocarbon sensor, finding 14 prospects for surface geochemical study and validation. Preliminary surface surveys have demonstrated active hydrocarbon micro- seepages over the 'benchmark' fields — Mereenie, Dingo and Palm Valley — and have covered six of the airborne hydrocarbon anomalies. Twenty- five designated areas remain to be prospected.
TL;DR: In this paper, a comparison between corrected bottom-hole temperature (BHT) and vitrinite reflectivity data from offshore petroleum exploration wells drilled in Tasmanian waters is made.
Abstract: Over the last three decades organic metamorphism (coalification), as indicated by changes in vitrinite reflectivity, has been regarded as a function of both temperature and heating duration. This temperature- time concept of coalification has been developed into sophisticated computer programs to model the palaeo- geothermal history of sedimentary basins. However, several papers, published over the last six years, have presented evidence to support the view that, for heating times in excess of 0.001- 1 Ma, vitrinite reflectivity constitutes an absolute palaeogeothermometer. This proposition is broadly supported by a comparison between corrected bottom- hole temperature (BHT) and vitrinite reflectivity data from offshore petroleum exploration wells drilled in Tasmanian waters. Most of the corrected BHT/vitrinite reflectivity data pairs plot on, adjacent to or between two of the published vitrinite temperature/reflectance trends. Although these data indicate that some formations are at, or near, maximum palaeotemperature, there is clear evidence to suggest that many samples, in particular those from formations in the deeper well sections, have cooled significantly below maximum palaeotemperature. It appears that present- day geothermal gradients for some of the wells, based on corrected BHT data, are much less than maximum palaeogeothermal gradients inferred from the vitrinite depth/reflectance relationship.