bluuebunny/crossref_metadata_2025 huggingface dataset:
BARROW ISLAND OILFIELD, REVISITED
Authors: Campbell I. R. , Tait A. M. , Reiser R. F.
Published: August 2017

Barrow Island is located 55 kilometres off the NW coast of Australia, 1300 kilometres north of Perth. The first well on the island, drilled by West Australian Petroleum Pty Limited (WAPET) in 1964, discovered a small accumulation of oil in Upper Jurassic sandstone. The fourth well was completed as a shallower oil discovery in the Lower Cretaceous Windalia Sandstone. The Windalia Pool was declared commercial in May 1966 and the first shipment of crude was made in April 1967.Production peaked at 7300 kilolitres (about 45 000 barrels) per day early in the life of the field and has declined to 3500 kilolitres (about 22 000 barrels) per day. Estimated original oil in place in the Windalia Pool is about 120 million kilolitres (about 760 million barrels) and current trends suggest 40 million kilolitres (250 million barrels) will be recovered.Pricing policies of the Australian Government have encouraged efforts to locate new reserves and extend the limits of known pools. These efforts on Barrow Island have led to the discovery of three new pools and the extension of the main Windalia Pool to the northwest. Two of the new pools are in unusual reservoir systems while the third has a significant stratigraphic component in its entrapment.To the end of 1983, WAPET had drilled 670 wells on the island. Further drilling is planned to evaluate the currently known pools and to try to locate further accumulations in this oil-rich area.
CRETACEOUS OF THE EROMANGA BASIN — IMPLICATIONS FOR HYDROCARBON EXPLORATION
Authors: Moore P. S. , Pitt G. M.
Published: August 2017

The Cretaceous sequence in the Eromanga Basin covers nearly one-fifth of the Australian mainland and has a maximum thickness of about 2000 m. The lowermost prospective unit is the Neocomian Cadna-owie Formation, which commonly contains hydrocarbon shows and recently yielded oil in Merrimelia 15. Likely source rocks include organic-rich sediments at the base of the overlying Bulldog Shale and Wallumbilla Formation. Future commercial production from the Cadna-owie Formation will be hampered by fine grain size and carbonate cements, resulting in low porosity and permeability. In southwestern Queensland, the Cadna-owie Formation appears to have been locally dissected by prominent channels. If sand-infilled, these channels will represent an interesting stratigraphic play, although they are likely to be mudstone-and diamictite-infilled submarine canyons, similar to those in the Tertiary Latrobe Group, Gippsland Basin. As such, they represent one component of a complex hydrocarbon play that has yet to be evaluated.A third, stratigraphically higher exploration target is the middle Albian Coorikiana Sandstone. Although the marine mudstones which encase the Coorikiana Sandstone are only poor to fair source rocks, hydrocarbon shows are common in the unit, which yielded 9900 m3 of gas per day when tested in Strzelecki 8. The potential of the unit is limited by poor reservoir quality and marginal oil maturity.The Toolebuc Formation, of middle-late Albian age, is the fourth promising target for significant hydrocarbons. The formation consists of organic-rich mudstone which is oil-shale bearing over large parts of Queensland. Minor oil and gas shows, attributed to early generation from a very rich source rock, suggest that oil production from the Toolebuc Formation may be possible if naturally fractured shale reservoirs can be located. Overall, the Cretaceous sequence in the southwestern Eromanga Basin is considered to have a modest oil and gas potential which should be evaluated in the course of drilling for deeper targets.It is emphasised that knowledge of Cretaceous and Cainozoic stratigraphy is essential in understanding the evolution of the Eromanga Basin. Rapid deposition of up to 2000 m of Cretaceous sediments enabled generation of hydrocarbons in the Jurassic sequence, beginning in the latest Cretaceous and continuing today. Although early, syn-sedimentary structuring and mild epeirogeny are evident in Cretaceous sediments, of far greater significance is a major phase of Early Tertiary folding, due probably to the effects of continental breakup and collision. This greatly enhanced pre-existing structures, produced some very large anticlines, and caused up to 800 m of the Cenomanian Winton Formation to be eroded from elevated areas. A complex interplay between timing of structural growth and maturation of the sequence is thus considered to be a major control on the present distribution of hydrocarbons in the Eromanga Basin.
SEISMIC LITHOLOGIC MODELLING
Authors: Gelfand Valery , Larner Ken
Published: August 2017

Seismic data constitute a noise-contaminated bandlimited representation of lithologic information. Therefore, attempts to recover lithologic information, such as velocity and density of thin layers, from seismic data cannot give a unique or verifiably correct result. Nevertheless, an interpreter must produce detailed geologic models on the basis of such data.Our interactive modelling procedure quantitatively refines the model that the interpreter derives from available geologic, borehole, and seismic data. The procedure starts from the initial model and perturbs its parameters (velocity, density, and layer thickness) to find the least-squares best fit between the stacked field data and the synthetic section derived from the model. The layer parameters are explicitly varied only at selected locations along the profile and are linearly interpolated to intermediate positions. This approach is based on an assumption of smooth lateral change for parameters, and enables the process to see through much of the noise.Synthetic data tests demonstrate that, even for significantly different initial models, the procedure can find solutions that are close to the correct model. Moreover, the procedure is stable in the presence of noise and not severely dependent on the shape of the bandlimited seismic signal or on details of the initial hypothesis.Application of the method to stacked data from the Denver Basin provides evidence that an interpreter's model can be refined so as to better match the seismic data while honouring available non-seismic data as well. A low-velocity anomaly in the final solution is well correlated with a known hydrocarbon play; the anomaly disappears near the dry well. Application of the method to stacked data from widely different data environments further demonstrates the value of the technique for refining thin-layer interpretations, thus providing, in effect, a geology-based deconvolution of seismic data.
TECTONICS OF THE JACKSON-NACCOWLAH AREA, COOPER-EROMANGA BASINS, SOUTHWEST QUEENSLAND, AND THEIR IMPLICATIONS FOR HYDROCARBON ACCUMULATION
Authors: Nelson A.W.
Published: August 2017

The Naccowlah-Jackson Trend in the Cooper-Eromanga Basins, southwest Queensland, has been the scene of a high hydrocarbon exploration drilling success ratio during the 1980s. The structural trend is mainly the result of sinistral convergent wrenching, which has given rise to a series of major reverse faults and two distinct series of relatively minor parallel and orthogonal basement faults. A parallel is drawn with fault patterns shown on a clay model study of a 15° convergent wrench fault. Productive structures result from intermittent growth on the fault trends since Early Permian, although original wrenching may have been pre-Permian. A releasing (divergent) fault bend is identified as an area of accumulation of a thick sequence of potential Permian source rock. Although this accumulation is well placed to have sourced the largest known oil accumulation on the trend, other drilling results tend to downgrade the potential of the local Permian sequence as a source.Structural growth due to wrenching has been responsible for a favourable integration of the components necessary for hydrocarbon generation and accumulation, but also appears to be responsible for crestal faulting which in several cases is interpreted to have led to the escape of hydrocarbons.Two basic oil types (Hutton type and Murta type) are known. The occurrence patterns of these are consistent with the Hutton type being derived from Jurassic source rocks, mature in the Nappamerri Trough, and the Murta type being sourced intra-formationally from source rocks which are marginally mature over most of the study area.
A DEPOSITIONAL MODEL FOR THE DUPUY MEMBER AND THE BARROW GROUP IN THE BARROW SUB-BASIN, NORTHWESTERN AUSTRALIA
Authors: Tait A.M.
Published: August 2017

A detailed sedimentological study of the Dupuy Member and the Barrow Group has resulted in a regional model for the deposition of these Upper Jurassic to Lower Cretaceous reservoir sequences in the Barrow Sub-basin. The Dupuy Member is interpreted as a prograding offshore slope sequence of turbidite sandstones and debris flows, which built laterally into the Barrow Sub-basin from along its eastern margin. This slope sequence contains bentonite markers in its upper part. The overlying Barrow Group was deposited by a delta which prograded along the length of the Barrow Sub-basin from the southwest and onlapped the Dupuy Member along the eastern side of the sub-basin. The topsets of the delta are fluvial to shallow marine sandstones, the foresets are offshore claystones, and the bottomsets are submarine mass-flow sandstones. After 8 million years of progradation, the delta was starved of sediment by continental breakup south of the Exmouth Plateau and stopped with its last foreset trending in an east-west arc from Barrow Island across the Exmouth Plateau. The Barrow Group delta was then gradually transgressed by the sea and blanketed by the Muderong Shale. Structural growth of the Barrow Island anticline took place during deltaic deposition and caused anomalous relationships between foresets and bottomsets under the north of Barrow Island. Known hydrocarbon accumulations and common shows in the Dupuy Member and the Barrow Group make these sequences attractive exploration targets.
MULTIPLE LAND USE — AN ESSENTIAL PART OF ENVIRONMENTAL PLANNING
Authors: Butler W.H.
Published: August 2017

The Australian petroleum industry has been involved in environmental planning and has developed an awareness of multiple land use over the past twentyfive years, more particularly over the past decade. This is in accord with the World Conservation Strategy and the National Conservation Strategy for Australia upon which the Australian State and Territory conservation strategies are based.As the term implies, multiple land use means a sharing of the land. The range of uses includes reserves, heritage areas, agriculture, urban and suburban development and mining. To achieve multiple land use requires the restoration of the environment to its pre-development state as quickly as possible so that both uses can be maintained. This requires that the new user assess the impact of his development well before it begins. This assessment is normally achieved through an Environmental Impact Statement (EIS) or Environmental Review and Management Plan (ERMP). Most operators are familiar with these requirements.This paper deals primarily with the restoration of the existing environment. Restoration is achieved by preserving, to the greatest extent possible, the vegetation and topsoil which are stripped from the development area. As little stockpiling as possible is done and the topsoil, mixed with the broken down vegetation, is returned as quickly as possible. In this way the contained seed load and nutrient values are not lost and regeneration results.Apart from the practical aspects there is a need for the workforce involved to understand what they are conserving and why they are conserving it. A delicate balance exists in nature wherein the surviving plants and animals are able to cope with natural disasters. Management plans must include the principle that the collective impact of a new development will at no time exceed the impact of natural catastrophes.
DEVELOPMENT OF THE WOODADA GAS FIELD
Authors: Lane C.M. , Watson R.J.
Published: August 2017

The Woodada gas field was discovered in May 1980, when the Woodada 1 well flowed gas at a rate of seven million cubic feet per day from a carbonate unit within the Carynginia Formation of the onshore northern Perth Basin. Appraisal and development drilling has resulted in a total of 11 wells, of which seven have produced sales gas.The reservoir is estimated to have contained initially at least forty four billion cubic feet of gas-in-place in the developed part. There is a prospective area to the south with similar potential.The Woodada field is a combination structural/strati- graphic trap, where an up-dip lithology change effecting a permeability barrier seals the reservoir across a north plunging anticline. Porosity within the reservoir is secondary, with natural fractures often contributing to the production mechanism. The presence of fractures has required special attention to drilling and completion techniques. Gas production is significantly enhanced by acidization.Pressure responses measured in or between wells combined with more than two years of production history have demonstrated that there is moveable gas in the fine voids of the matrix rock, as well as in the better developed secondary porosity system. Even where there is no substantial porosity in a well bore, it has been possible to achieve commercial production rates by acid stimulation.
EXTENSIONAL BASIN — FORMING STRUCTURES IN BASS STRAIT AND THEIR IMPORTANCE FOR HYDROCARBON EXPLORATION
Authors: Etheridge M.A. , Branson J.C. , Stuart-Smith P.G.
Published: August 2017

The Bass, Gippsland and Otway Basins of southeastern Australia were initiated by north-northeast to south- southwest lithospheric extension, largely during the Early Cretaceous. The extensional stage was followed by a Late Cretaceous to Pliocene thermal subsidence stage and a late stage of compressional tectonic overprinting.The extensional stage was dominated by two orthogonal fault sets - shallow to moderately dipping, rotational, normal faults and steeply dipping, transfer (transform) faults. Thermal subsidence involved vertical rather than horizontal movements, and consequently generated a discrete fault geometry, comprising steep, down-to-basin, normal faults with small displacements. The major extensional structures exerted a range of controls on both sedimentation and structuring during the subsidence stage. Likewise, the location and style of late Tertiary compressional structures overprinted on the Gippsland and, to a lesser extent, Bass and Otway Basins are controlled by reactivation of major early normal and transfer faults. In particular, the Kingfish, Mackerel, Halibut, Flounder and Tuna fields in the Gippsland Basin overlie a single Early Cretaceous transfer fault zone that was a basinwide structural boundary during extension. These fields occupy en echelon compressional structures generated by left-lateral wrench reactivation of the transfer zone during late Tertiary northwest-southeast compression. The major extensional structures have had an important influence on all stages of the evolution of these basins. It is contended that a thorough understanding of their extensional framework is an important factor in hydrocarbon exploration of these and other basins.
A CASE FOR A NATIONAL PIPELINE GRID FOR NATURAL GAS
Authors: Campbell G.D.
Published: August 2017

The development of an integrated natural gas pipeline system should be a goal within a national energy policy for Australia. Australia has in excess of 100 years supply of natural gas in the proved and probable category and another 250 years of supply that we can expect to find with reasonable confidence.There are clear indications that if markets can be created or developed, gas producers will respond by establishing reserves to service those markets. A recent example is the rapid increase in proved/probable reserves established in the Amadeus Basin following the Northern Territory Government's interest in constructing a pipeline to Darwin.The Australian Gas Association has taken the view that reserves will be a limiting factor in natural gas development and hence pipeline systems will only be developed to access more remote and expensive fields as the current reserves are depleted. This paper takes the contrary view that natural gas reserves eventuate from market driven policy. That is, if an attractive market is opened to natural gas then reserves will be forthcoming.A number of policy guidelines which would allow the economic development of a national natural gas grid are the key incentives for the explorers.Utilisation of natural gas for the generation of electricity in New South Wales to the extent of 10 per cent of the annual load would enhance the performance of the total electrical system. By providing this substantial natural gas market an economic basis can be provided for the proposed national grid links.For the electrical generation market in New South Wales gas producers should be guaranteed a well head price of say $1.50 to $2.00 a gigajoule for onshore gas.
HYDROCARBON SOURCE POTENTIAL OF THE GOLDWYER FORMATION, BARBWIRE TERRACE, CANNING BASIN, WESTERN AUSTRALIA
Authors: Foster C.B. , O'Brien G.W. , Watson S.T.
Published: August 2017

The Goldwyer Formation is widely known from the subsurface Canning Basin, Western Australia. Microfossils of acritarchs, chitinozoans, and conodonts, and macrofossil remains, indicate it was deposited in a normal marine environment in late Early to Middle Ordovician times (Late Arenig to Llanvirn). In Exploration Permit areas 143 and 225, the Formation is subdivided into four lithologic members, informally designated Units 1 to 4 in ascending stratigraphic order. Horizons within Unit 4, immediately underlying the prospective reservoir dolostones of the Nita Formation, are organic rich with between 0.5 and 6 per cent total organic carbon. Generative potential of these horizons, determined by Rock-Eval, averages 13 litres of hydrocarbon per tonne. A conservative estimate of the cumulative thickness of source rock with hydrogen index (HI) values of 300-900, using whole core fluorescence intensity, is 10 m. Thus, under optimum maturation conditions there is potential for generation of an estimated 61 × 109 barrels of liquids from Unit 4 within EP 143 and EP 225. These figures are based on an integrated analysis of 44 core samples from four fully cored 'slim holes' and cores from one conventional oil well. Kero-gen types and measures of organic maturity cannot be determined accurately from the standard Rock-Eval HI/Tmax crossplot. The dominant oil-prone kerogen in Unit 4 is Gloeocapsamorpha prisca Zalessky 1917 and palynological and gas chromatographic/mass spectrometric studies correlate it with Ordovician kerogens from the Baltic Basin, Michigan and Illinois basins, and Amadeus Basin. Gas chromatographic/mass spectrometric source rock-oil correlations show that oils from the Williston Basin (USA), Canning Basin, and Amadeus Basin are derived predominantly from G. prisca. Palaeogeographic reconstructions suggest that these areas lay within 5° north and south of an Ordovician equator and so provide data for further prediction of possible rich hydrocarbon source areas.
TO TACKLE THE DECONVOLUTION PROBLEM — A POWERFUL METHOD BASED ON MORE GEOLOGICAL HYPOTHESES
Authors: Denelle E.
Published: August 2017

The new rules of the game in hydrocarbon exploration demand an exact positioning of the seismic markers in order to define the geometry of the targets more than ever before. However, the degree of success will depend to a great extent on how accurately the amplitude of reflection coefficients can be estimated.These new requirements mean that all stages of traditional seismic processing have to be critically evaluated. It can be seen, in particular, when assessing existing deconvolution methods for seismic processing, that they are often ill-conditioned to problems posed by the targets of stratigraphic exploration or by reservoir seismic prospecting. The amplitude of the reflectivity function is often estimated inaccurately.The approach described in this paper abandons the usual hypothesis (white reflectivity spectra) made by deconvolution methods and employs as alternative information the lateral redundancies which are always present on a seismic section. Our method first estimates the location of high amplitude reflectors with good lateral continuity, by means of an elegant automatic picking program. Based on these locations, a generalized inversion can be used to yield the wavelet emitted by the source, and the amplitude of the main reflection coefficients simultaneously for each trace. All the reflection coefficients are then estimated using the amplitudes and the wavelets computed previously.The various stages of this method which is called Deconvolution-Inversion, developed by Total Compagnie Française des Pétroles, are illustrated in the paper by means of both synthetic and real examples. The ability of the method to preserve the amplitudes makes it a powerful tool for stratigraphic and reservoir seismic prospecting purposes.
FRESHWATER INFLUX IN THE GIPPSLAND BASIN: IMPACT ON FORMATION EVALUATION, HYDROCARBON VOLUMES, AND HYDROCARBON MIGRATION
Authors: Kuttan K. , Kulla J.B. , Neumann R.G
Published: August 2017

The recognition and quantitative evaluation of hydrocarbon zones in the Gippsland Basin is complicated by the presence of a freshwater aquifer system. This aquifer system has been verified and documented using data obtained from wireline logs. The presence of freshwater aquifers below the hydrocarbon sands leads to (i) difficulty in distinguishing the hydrocarbon zones from the water sands using well logs, and (ii) difficulty in determining accurate water saturation values used in estimating hydrocarbon volumes.Water saturations calculated from logs require the input of a formation water salinity. In conventional log analysis the formation water salinity in the hydrocarbon zones is assumed to be the same as that of the underlying water sands. In reservoirs in the Gippsland Basin underlain by freshwater aquifers, calculated water saturations using the salinities of the water sands are inconsistent with capillary pressure, Repeat Formation Tester (RFT*-Schlumberger), and production test data. All available evidence suggests that the formation water salinities within the hydrocarbon zones are significantly greater than in the freshwater aquifers. The water saturations derived using the higher salinity values lead to the calculation of greater hydrocarbon volumes.The occurrence of saline formation waters within the hydrocarbon zones leads to the interpretation that significant volumes of hydrocarbon were emplaced prior to the formation of the freshwater aquifer system. Subsequent freshwater influx did not flush the emplaced hydrocarbons.
DISCOVERY AND EXPLOITATION OF NEW OILFIELDS IN THE COOPER-EROMANGA BASINS
Authors: Lavering L.H. , Passmore V.L. , Paton I.M.
Published: August 2017

Since 1975 the level of petroleum exploration in the Cooper-Eromanga basins has undergone an unprecedented expansion due to the discovery and development of an increasing number of oil reservoirs, largely in the Eromanga Basin sequence. The commercial incentive provided by the Commonwealth Government's Import Parity Pricing and excise arrangements have been instrumental in the lead up to and continuation of this series of discoveries.Three types of oil discovery in the Eromanga Basin sequence are evident; firstly, shallow pools above Cooper Basin gas fields; secondly, separate single-field discoveries in areas of limited exploration; and thirdly, as multifield discoveries along major structural trends. Exploitation of the Eromanga Basin oil discoveries has been made possible by a combination of rapid appraisal and development drilling and early commencement of production.The initial Eromanga Basin oil discoveries overlie major Cooper Basin gas fields and were located during appraisal and development drilling of deeper Cooper Basin gas reservoirs. Wildcat and appraisal drilling on Eromanga Basin prospects, such as Wancoocha and Narcoonowie, has upgraded the prospectivity of the Eromanga Basin sequence in the southern Cooper Basin—an area where earlier exploration for Cooper Basin gas was unsuccessful. Significant oil discoveries in Bodalla South 1 and Tintaburra 1, in the Queensland sector of the Eromanga Basin, have extended the range of exploration success and generated considerable interest in lesser known parts of the Eromanga Basin.Three successive phases of Cooper-Eromanga exploration have led to the present high level of success. Early exploration, before 1969, led to the initial discovery and development of Cooper Basin gas fields and was largely supported by the Petroleum Search Subsidy Acts (19571974). The results of the second phase, between 1970 and 1975, provided little encouragement to operators to extend exploration beyond the limits of the then known gas accumulations. In the decade since 1975, the oil potential of the Eromanga and parts of the Cooper Basin sequences has become a major factor in the exploration and development activity of the region. Since 1975, the favourable commercial conditions prevailing under the Import Parity Pricing scheme and the concessional crude oil excise arrangments for production from 'newly discovered' oilfields provided a significant incentive for development and exploitation of the post-1975 oil discoveries.
THE TINTABURRA OILFIELD
Authors: Newton C.B.
Published: August 2017

The Tintaburra oilfield, discovered in December 1983 with the drilling of Tintaburra 1, is situated within Petroleum Lease 29 (previously within Authority to Prospect 299P Part 2) on the southeast margin of the Eromanga Basin, Queensland.Tintaburra 1 recorded the first flow of oil from the Cretaceous Wyandra Sandstone Member of the Cadnaowie Formation in the Eromanga Basin and established the presence of oil columns in the Murta Member and Hutton Sandstone. The Hutton Sandstone produced 1750 barrels of 44° API gravity oil per day on drill stem test.The results of six successful appraisal wells show the field to be a simple structural accumulation at the top Hutton level. The top Hutton accumulation is believed to be full to fault-independent closure. The hydrocarbons are trapped on the western upthrown side of the Tertiary reverse faulted Tintaburra Anticline. Approximately 80 per cent of reserves are reservoired in the top Hutton.The discovery extended the productive limits of the Eromanga Basin 100 km to the north and east from theJackson oilfield, and highlighted the potential of Tertiary structures, previously thought by many to be non-prospective.Channelling at the 'C' horizon (base Wallumbilla Formation) extends across the southern part of the field, complicating depth mapping by virtue of the large velocity contrasts between channel and host sediments. Velocity and raypath distortion below the channel are major geophysical complexities that have been successfully overcome, allowing more accurate location of appraisal wells.Appraisal drilling, combined with high quality seismic data, has identified the nature of the Early Cretaceous submarine channelling, and has identified new channel-related plays. 'C' horizon channelling imparts a strong stratigraphic component to the Murta and Wyandra accumulations. Integrated core and log studies indicate that every reservoir within fault-independent closure, and overlain by a laterally continuous effective seal, contains oil. Facies variations within the top Hutton/base Birkhead interval have important implications for trap integrity and are generally not resolvable seismically.The high API gravity, low pour point Wyandra and Murta crudes are distinct from the waxy, paraffinic Hutton crudes, and geochemical analysis of the oils and source rocks indicates a probable Eromanga-sequence origin for all the crudes.
SALES GAS AND ETHANE STORAGE PROJECTS—MOOMBA FIELD, LOWER DARALINGIE BEDS
Authors: Kelemen S.G.
Published: August 2017

The Lower Daralingie Beds of the Moomba Field were first used for storage in 1981 with the startup of the Sales Gas Storage Project. The Ethane Storage Project was initiated in 1984, and both storage projects are now being operated simultaneously in this reservoir.Sales gas is being stored for the purpose of providing peak shaving capacity during periods of high demand, while ethane is being stored to guarantee feedstock requirements if a petrochemical market eventuates. At present three wells are being used for ethane storage in the northern portion of the Lower Daralingie Beds, and in the southern portion two wells are being used for sales gas storage.The Lower Daralingie Beds were partially depleted prior to being converted to a storage reservoir. In the South Dome of the Moomba Field the reservoir consists of two gas bearing sandstone units which can be correlated across the field. The average net pay of the storage wells is 7 ft with flow capacity varying up to 3300 md-ft. Production rates up to 1.6 × 106 m3/d (58 × 106 ft3/d) have been recorded from 11 ft of sand.
RESERVOIR SIMULATION IN THE MEREENIE FIELD
Authors: Towler B.F.
Published: August 2017

The Mereenie Field in the Amadeus Basin was discovered in 1964 and contains an estimated 240 million barrels of oil and 480 billion (USA) cubic feet of gas in three formations. The field commenced production at 1500 barrels of oil per day from seven wells in September 1984. The structure is large and elongated and the oil in the permeable sands appears as a rim round the structure. This paper describes a reservoir simulation study initiated to evaluate the recovery of oil from wells sited on the north and south flanks of the anticline where the steep dips cause the oil rim to become very narrow.Ten studies were made on a 21 × 15 cell pattern model using a three phase semi-implicit black oil reservoir simulator. The ten runs compared oil recovery and gas/oil ratio as a function of formation dip, bottom hole flowing pressure, gas injection and water injection. These showed that the flank wells could be expected to recover 300 000 stock tank barrels of oil from primary and secondary operations which represents about 25 per cent of the oil in place for wells sited on half mile spacings. However the wells will experience high gas/oil ratios and a steep decline in oil rate.
FOSSIL RESIN BIOMARKERS AND THEIR APPLICATION IN OIL TO SOURCE-ROCK CORRELATION, GIPPSLAND BASIN, AUSTRALIA
Authors: Alexander R. , Noble R.A. , Kagi R.I.
Published: August 2017

Diterpanes occur widely in the resins of modern conifers, suggesting that sedimentary diterpanes are chemical markers for fossil resins, particularly those derived from conifers. In this paper, the use of the relative abundance of these chemical fossils for establishing genetic relationships between the organic matter in sediments and crude oils has been demonstrated using sediments and crude oils from the Gippsland Basin.The crude oils were characterised by their remarkably uniform distributions of diterpanes and similar relative amounts of diterpanes and hopanes. In contrast, the sediments showed much greater variability, with only one sediment horizon, an organic-rich shale, showing the same properties as the crude oils.
ORGANIC PETROLOGY OF LIPTINITES IN THE DENISON TROUGH, QUEENSLAND
Authors: Beeston J.W.
Published: August 2017

Liptinite macerals in the Denison Trough are derived from a wide range of organisms including marine acritarchs, and non-marine algae, lycopods, articulates, ferns and gymnosperms. They are formed from the lipid and wax-rich components of these organisms, in particular from specialised tissues, leaves and reproductive organs developed for protection and/or energy storage. They occur chiefly in terrestrially deposited sediments and coals, yet their distribution is variable amongst the seven coal facies assemblages and six disseminated organic matter (DOM) suites distinguished in the trough. The most abundant liptinites are derived from miospores, leaf cuticles and algae. Miosporinite averages 2.6 per cent of total rock and is most abundant in coal seams, banded coals and carbonaceous mudstones that were deposited in ponds, abandoned channels and intraswamp lakes, where it ranges up to 14 per cent. Cutinite averages 0.7 per cent of total rock, and is most abundant in coal seams and banded coals that were deposited as leaf banks in shallow water marginal to peat swamps, where it ranges up to 10 per cent. Alginite averages 0.1 per cent of total rock, and is most abundant in mudstones that were deposited in lake margin ponds, where it ranges up to 22 per cent. Preservation of liptinites (as determined by fluorescence) is best where they were deposited in a quiet regime, at or near their sites of origin, in concentration. In some of these situations they occur in association or juxtaposition with the highly fluorescing, non-structured macerals sporogenite, phylloresinite and fluorinite. The latter are suggested as remnants of material that has otherwise yielded oil.
A QUEST FOR A NEW PARAMETER IN PETROLEUM EXPLORATION GEOCHEMISTRY
Authors: Smith J.W. , Gilbert T.D.
Published: August 2017

Primary Australian terrestrially-derived crudes are characterised by high wax and n-alkane contents. These characteristics, as determined by hydrogenation and hydrous pyrolysis, appear to be unrelated to either the chemical or petrographic compositions of Victorian brown coal lithotypes. Furthermore, since relationships between chemical and petrographic composition are obscure, a re-examination of current concepts which relate these established source rock parameters to liquid hydrocarbon generating potentials is warranted.The content of thermally stable, longer-chain, n-alkyl components in source rocks is introduced as the critical factor in determining whether these rocks have the potential to generate typical Australian waxy crudes or hydrocarbon gases. Modifications to this general concept are required by the thermal stability of directly substituted longer-chain n-alkyl aromatics and hydroaromatics. These appear to be sources of light hydrocarbons and gases, rather than oils.Inherent weaknesses in the experimental techniques of hydrogenation and hydrous pyrolysis have hindered the collection of data, but the concept that n-alkane potential is a critical factor in determining the petroleum-generating potential of immature source rocks is being pursued using techniques modified for the determination of their total heteroatom-bonded n-alkyl contents.
THE GEOLOGY OF THE HARRIET OILFIELD, OFFSHORE WESTERN AUSTRALIA
Authors: Osborne D.G. , Howell E.A.
Published: August 2017

The Harriet Oilfield, discovered in November 1988, is situated within offshore permit WA-192-P in the Barrow Sub-basin. Following the Harriet 1 discovery well, detailed seismic surveys were recorded and a further ten wells were drilled on the structure between 1988 and 1985. Nine of the wells were completed as producers and one was plugged and abandoned as a dry hole.The oil accumulation occurs in a low relief, fault-dependent closure on the upthrown side of the Lowendal Fault. The trap is mainly structurally controlled but stratigraphic barriers are believed to be locally present, based on differing oil-water contacts in Harriet B-3 and Harriet A-5. These indicate the presence of three hydrocarbon pools separated by permeability barriers.The massive Flag Sandstone reservoir of Lower Cretaceous (Neocomian) age was deposited in a submarine fan environment, northward of the advancing Barrow Group delta. Reservoir quality is very good, with average core porosity of 22 per cent and permeabilities mainly in the range 800-2 000 md. However, a broad oil-water transition zone is developed above the oil-water contact. A residual oil zone is present below the oil-water contact in the northeastern area of the field, suggesting tilting of the structure after initial accumulation of the oil. The gross oil column in the main, Central Pool is 19-21 m with a gas cap up to 10 m thick. The 37° API crude is a relatively unaltered, high quality, paraffinic oil probably sourced from the Jurassic Dingo Claystone.The Harriet Field is the first commercial development of a Barrow Group hydrocarbon accumulation. Recoverable oil reserves are currently estimated at 21 million barrels. The field came on stream in January 1986 and by October 1986 oil production was averaging 10 000 barrels/day.
LITHOSTRATIGRAPHY OF THE LOWER EROMANGA BASIN SEQUENCE IN SOUTH WEST QUEENSLAND
Authors: John B.H. , Almond C.S.
Published: August 2017

Five fully-cored and wire-line logged stratigraphic bores have been drilled by the Queensland Department of Mines, relatively close to producing oil fields in the Eromanga Basin, south-west Queensland. Correlations between the stratigraphic bores and petroleum wells have established lithologic control in an area where lithostratigraphy is interpreted mainly from wire-line logs. The Eromanga Basin sequence below the Wallumbilla Formation has been investigated, and a uniform lithostratigraphic nomenclature has been applied; in the past, an inconsistent nomenclature system was applied in different petroleum wells.Accumulation of the Eromanga Basin sequence was initiated in the early Jurassic by major epeirogenic downwarping; in the investigation area the pre-Eromanga Basin surface consists mainly of rocks comprising the Thargomindah Shelf and the Cooper Basin. The lower Eromanga Basin sequence in the area onlaps the Thargomindah Shelf and thickens relatively uniformly to the north-west. The sequence comprises mainly Jurassic/Cretaceous terrestrial units in which vertical and lateral distribution is predominantly facies-controlled. These are uniformly overlain by the mainly paralic Cadna-owie Formation, signalling the initiation of a major Cretaceous transgression over the basin.The terrestrial sequence over most of the area comprises alternating coarser and finer-grained sedimentary rocks, reflecting major cyclical changes in the energy of the depositional environment. The Hutton Sandstone, Adori Sandstone and 'Namur Sandstone Member' of the Hooray Sandstone comprise mainly sandstone, and reflect high energy fluvial depositional environments. Lower energy fluvial and lacustrine conditions are reflected by the finer-grained sandstone, siltstone and mudstone of the Birkhead and Westbourne Formations, and 'Murta Member' of the Hooray Sandstone. Similar minor cycles are represented in the 'basal Jurassic' unit. The Algebuckina Sandstone, recognised only in the far south-west of the investigation area, comprises mainly fluvial sandstones.
SOUTH-WEST QUEENSLAND GAS — A RESOURCE FOR THE FUTURE
Authors: Cosgrove J.L.
Published: August 2017

Natural gas has been discovered in 22 fields in the Central Eromanga and Cooper Basins of southwestern Queensland in the area comprised by ATP 259P. Proved, probable and possible reserves in excess of 36 × 109 m3 (1.27 TCF) are located in four discrete structural provinces. Fluvial sandstones of the Early Permian Patchawarra Formation and Late Permian Toolachee Formation contain the majority of the reserves. Minor amounts of gas are reservoired in the Early Permian Epsilon Formation, the Early-Middle Triassic Nappamerri Formation and the Early Jurassic Hutton Sandstone and Birkhead Formation. Considerable gas-liquids reserves are also found in these reservoirs.Existing reserves are located primarily in structural traps although lithofacies variations are widely recognised, particularly in the Patchawarra Formation, indicating both new play opportunities and difficulties in assessing the undiscovered gas potential of the permit. Additional gas potential is identified in flank areas of the more prominent structural axes such as the Jackson-Wackett-Innamincka Trend in fault-bounded, pinchout and sub-unconformity trapping configurations.More than 200 prospects and leads are identified with the potential to entrap approximately 51 × 109 m3 (1.80 TCF) of gas on an unrisked basis. When combined with reserves from established fields, the ultimate potential of the ATP is assessed as 87 × 109 m3 (8.10 TCF).Despite the very high success rate of previous exploration and appraisal programs, the ultimate gas potential of the Queensland portion of both the Cooper and Eromanga Basins has been only partially addressed. Exploration and appraisal programs providing future additions to proved and probable reserves are considered low risk and are dependent upon an agreement with the Queensland government that would enable the ATP holders to produce and sell gas interstate.
THE DETECTION AND SIGNIFICANCE OF FRACTURES IN THE PALM VALLEY GAS FIELD
Authors: Do Rozario R.F. , Baird B.W.
Published: August 2017

The Palm Valley Gas Field was discovered in March 1965 when the Palm Valley 1 well flowed up to 11.7 million cubic feet of gas/day from Ordovician sandstones and carbonates. Since then, a further five wells have been drilled, with a wide variation in gas flow rate, from less than one million, to over 130 million cubic feet/day.Matrix porosities and permeabilities are generally very poor to poor; however, cores, log analysis, and interference tests confirm the presence of an extensive fracture network providing the main permeability conduit for gas production.Recent drilling (Palm Valley 4, 5 and 6) has enabled a comprehensive suite of modern wire-line logs to be run with the specific aim of identifying the location and orientation of fractures. From analysis of the resultant data, it can be demonstrated that both fracture direction and concentration vary significantly from well to well, giving rise to corresponding differences in productivity. Fracture occurrence also varies from fractured zones that parallel bedding planes and may be correlatable from one well to another, to vertical or semi-vertical fractures that intersect the borehole diagonally.High well productivity can be correlated with greater fracture density, which in the Palm Valley Field has so far been proven to occur along the axis of the anticline, as well as with the intersection of major fractured 'zones' displaying a dominant fracture orientation sub-parallel to parallel to that of the principal residual stress.
GEOLOGICAL CONTROLS ON RESERVOIR QUALITY OF THE NORTHERN PERTH BASIN
Authors: Bergmark S.L. , Evans P.R
Published: August 2017

The major onshore Dongara gas field and a number of adjacent minor gas and oil pools are reservoired in basal Triassic sandstones that are sealed by the overlying Kockatea Shale. Reservoir quality is found to be controlled primarily by the local provenance of the sandstones, by diagenesis and the regional palaeotopography. Sandstones east of Dongara are reworked products of a Late Permian fan delta (Wagina Sandstone) that extended westwards from the basin's eastern, fault controlled margin. Localised high energy streams drained the palaeoslope, depositing thin wedges of mainly fluvial sediments upon and around the flanks of the Permian fan delta during a regional rise in sea level in the Early Triassic. Sandstones to the north of Dongara are localised, low energy offshore bars and strandline deposits derived from Precambrian of the Northampton Block. Diagenetic alterations of the Triassic sandstones, also controlled by the sandstones' provenance, have substantially reduced primary porosity and control permeability. The common presence of the authigenic clay mineral, dickite, is taken as evidence that a fluvial environment of deposition controlled formation of the reservoir rocks.
SUBSEA PRODUCTION FOR WELLS DRILLED FROM JACKUP DRILLING UNITS
Authors: Thatcher M. , Marietta D.B.
Published: August 2017

Subsea production systems have been an accepted method of developing offshore oil and gas fields since the installation of the first subsea trees in the early 1960s offshore California. Generally subsea completions have been done from floating drilling vessels on wells with subsea wellhead equipment. A number of wells have been completed subsea by bottom supported jackup rigs on wells drilled using mudline suspension equipment. The subsea completion equipment and methods utilised to adapt mudline suspension wells for a subsea production tree are described. This method of completion offers important benefits as it allows completion of wildcat or delineation wells, it can be used in areas of small, scattered reservoirs, and it can be used in conjunction with floating production systems. The cost associated with these subsea completions is roughly equivalent to those of standard subsea completions from floating vessels. An overview of a typical completion system is presented and compared.
THE SUCCESSFUL RECOVERY OF WELL PRODUCTIVITY IN THE BODALLA SOUTH OILFIELD
Authors: Dolan P. , Griffiths P.D. , Welton S.R.
Published: August 2017

The Bodalla South oilfield is located in the Cooper-Eromanga Basin, south-west Queensland. The field consists of two main oil reservoirs, the Hutton and basal Jurassic sandstones of the Eromanga Basin sequence. Several of the development wells drilled into these reservoirs exhibited high skin factors which resulted in reduced well productivities. These skin factors were also seen to increase with production from these wells. Core studies on samples from the Hutton and basal Jurassic reservoirs revealed the presence of migrating fines and showed that the fines were predominantly kaolinite clay particles. A formation damage study showed that the initial formation damage, created by drilling and completion operations, acted as a barrier to these mobile fines and resulted in the increasing formation damage. The study concluded that the damage can be removed by the underbalance re-perforation of the particular intervals.A four well workover program was undertaken at Bodalla South with the aim of the underbalance re-perforation of producing intervals with substantial formation damage. These complex workovers involved dual string tubing-conveyed perforation operations along with appropriate completion techniques. A mixed KCl/NaCl brine containing a clay stabiliser was used and was filtered through a filter cartridge system to remove all particles greater than 10 microns. Compressed nitrogen from standard gas bottles was used along with crude oil to achieve the 1 000 psi underbalance required for the re-perforation of the reservoir intervals.The workovers were very successful in restoring the productivity of the damaged intervals; in one case, oil production increased from 160 b/d to around 1 600 b/d. This improved production performance has been sustained. The workovers were complex and expensive, costing in total around A$800 000. However, payback was achieved, in one instance, within one month.
THE SNAPPER DEVELOPMENT, GIPPSLAND BASIN
Authors: Clenton P.N.
Published: August 2017

The Eocene N-I reservoir at the top of the Latrobe Group at Snapper is the second largest gas accumulation discovered to date in the Gippsland Basin. Oil reserves exist in a four to eight metre oil leg below this gas pool and in various small intra-Latrobe Group reservoirs.Development drilling took place in two phases, between 1981 and 1987, with exploitation of the N-I gas reserves being the long term aim. However, initial emphasis has been to maximise production from the N-I oil column. This was the first significant development of a thin oil column in the Gippsland Basin and required detailed study of the reservoir stratigraphy, accurate mapping and the drilling of a number of costly, ultra-high angle wells.The N-I oil leg required intensive development because each well provides only limited drainage, despite the generally excellent reservoir quality. Recovery is limited by gas and water coning, shale and coal units that act as barriers to drainage and, in some areas, by the presence of dolomitic cement in the reservoir.After all 27 conductors had been used for development drilling, 5 unsuccessful or depleted wells were redrilled to additional N-I oil development targets. The Federal Government granted a 'Substantial New Development' classification to these wells before they were drilled. This provided a reduction in excise on part of the oil produced from them. The targets were small and difficult to reach and would not have been viable without this reduction.