bluuebunny/crossref_metadata_2025 huggingface dataset:
THE PRACTICAL APPLICATION OF THE INCOME TAX ASSESSMENT ACT TO THE PETROLEUM MINING INDUSTRY
Authors: Moore R. K.
Published: August 2017

Division 10AA of the Income Tax Assessment Act provides a basis for deductibility of exploration and capital expenditure for the petroleum, oil and gas industries, with Division 10AAA allowing deductions for transport and port facilities. The taxpayer has the choice of electing out of Division 10AA so that, if he so wishes, he may claim income tax deductions under the normal depreciation provisions for plant depreciable. Within the framework of Division 10AA exploration expenditure may be written off in the year of expenditure to the extent of the net assessable income derived from any source. If there is any excess exploration expenditure it carries forward into an exploration pool and is available for deduction against future assessable income. For a deduction to be available for exploration expenditure, the Commissioner must be satisfied that the taxpayer is carrying on prescribed petroleum operations or a business which includes exploration or prospecting for the purpose of discovering petroleum. The Commissioner generally adopts the attitude that to enable the taxpayer to claim a deduction for exploration expenditure the taxpayer must have an interest directly or indirectly in the permit area.Capital expenditure can be deducted over a 10 year period at the fixed rate of 10 per cent per annum. Expenditure on transport and port facilities, if eligible, can also be deducted over a fixed instalment period of 10 years. Special provisions apply in relation to farm-ins and farm-outs, and where work is carried out by contractors. There is no specific incentive to invest money in the exploration business apart from the 27 per cent rebate found in Section 160ACA. The main provisions of the Income Tax Assessment Act affecting petroleum, oil and gas are summarized, some of the difficulties and the attitude of the Commissioner to the applications of the various sections are explained, and ways of treating certain expenditures are suggested. Topics such as drilling funds are discussed in detail.The Income Tax Assessment Act was basically written prior to the development of the petroleum industry and the Act itself adopts a rather simplistic approach which does not deal in depth with many of the important aspects of petroleum mining operations.
GEOLOGY OF THE DELLA FIELD, A PERSPECTIVE ON THE HISTORY OF THE COOPER BASIN
Authors: Gravestock D. I. , Morton J. G. G.
Published: August 2017

The Della Field produces dry gas from stacked fluvial sandstone reservoirs in the Early Permian Patchawarra Formation and Late Permian Toolachee Formation. Localised but severe fault activity and erosion in the late Early Permian have resulted in structural and stratigraphic complexities, particularly on the western flank of the field.A detailed study of lithofacies associations from cores has enabled constraints on the resolution of petrophysical logs to be appreciated. Within these constraints major facies associations are mappable across the field. Active channel migration in the Patchawarra Formation resulted in erosion and hence incomplete preservation of the fluvial sequence, which hinders mapping across the field. In contrast, the successive fluvial cycles of the Toolachee Formation are more completely preserved, enabling intrafield and some interfield correlation and mapping. The contrast is due to changing responses of the fluvial regime to prevailing tectonic conditions.A preliminary fluvial facies model, proposed after the first six Della wells, was upgraded during development drilling, with the result that productive reservoirs were successfully predicted. Integration of all available data provides one perspective on the evolution of the Cooper Basin in South Australia.
THE DEVELOPMENT OF THE TIRRAWARRA OIL AND GAS FIELD
Authors: Pecanek H. T. , Paton I. M.
Published: August 2017

The Tirrawarra Oil and Gas Field, discovered in 1970 in the South Australian portion of the Cooper Basin, is the largest onshore Permian oil field in Australia. Development began in 1981 as part of the $1400 million Cooper Basin Liquids ProjectThe field is contained within a broad anticline bisected by a north-south sealing normal fault. This fault divides the Tirrawarra oil reservoir into the Western and Main oil fields. Thirty-four wells have been drilled, intersecting ten Patchawarra Formation sandstone gas reservoirs and the Tirrawarra Sandstone oil reservoir. Development drilling discovered three further sandstone gas reservoirs in the Toolachee Formation.The development plan was based on a seven-spot pattern to allow for enhanced oil recovery by miscible gas drive. The target rates were 5400 barrels of oil (860 kilolitres) per day with 13 million ft3 (0.37 million m3) per day of associated gas and 70 million ft3 (2 million m') per day of wet, non-associated gas. Evaluation of early production tests showed rapid decline. The 100 ft (30 m) thick, low-permeability Tirrawarra oil reservoir was interpreted as an ideal reservoir for fracture treatment and as a result all oil wells have been successfully stimulated, with significant improvement in well production rates.The oil is highly volatile but miscibility with carbon dioxide has been proven possible by laboratory tests, even though the reservoir temperature is 285°F (140°C). Pilot gas injection will assess the feasibility of a larger-scale field-wide pressure maintenance scheme using miscible gas. Riot gas injection wells will use Tirrawarra Field Patchawarra Formation separator gas to defer higher infrastructure costs associated with the alternative option of piping carbon dioxide from Moomba, the nearest source.
DIAGENESIS AND THE EVOLUTION OF GIPPSLAND BASIN RESERVOIRS
Authors: Bodard J. M. , Wall V. J. , Cas R. A. F.
Published: August 2017

Key findings of this study on the nature, distribution and influences of diagenetic modifications to the Latrobe Group, Gippsland Basin, are: The Latrobe Group sandstones do not exhibit the regular porosity/depth patterns regarded as typical for many sedimentary basins. Dolomite cements are widely though variably developed in sandstones that are characteristically medium-to very coarse-grained, matrix-poor, texturally and mineralogically mature. These cements fill pore spaces, exhibit partial framework replacive textures, and may comprise as much as 30 per cent of total rock volume. In Flounder, Snapper, Tuna, Marlin, and probably other fields dolomite cementation is the major cause of porosity reduction. Sandstone porosity, notably in the above examples, is largely secondary and principally derived from the dissolution of precursor dolomite cements. Advanced dissolution results in exceptionally high porosity and permeability, and is largely responsible for the character of Snapper, Marlin, Tuna, Flounder and probably other reservoirs. Dedolomitization appears to be closely associated with hydrocarbon emplacement. Another important form of secondary porosity, developed in sandstones lacking evidence of extensive dolomitization, results from the dissolution of clay matrix. This contributes significantly to Mackerel. Hapuku, Kingfish and Halibut reservoir quality. Feldspar and rock fragment dissolution and alteration, as well as intra-clast fracturing, also contribute minor secondary porosity. Secondary porosity may subsequently be reduced by authigenic kaolinite (with or without illite) and rare chlorite filling, quartz cementation, framework restructuring and compaction, such as is typical of Bream, deeper Barracouta, Snapper, Tuna and other deeper arenite strata. Chemical modelling of the interaction between dolomite and aqueous fluids indicates that large volumes of fluid are necessary to effect dolomite precipitation and dissolution. Variation in pH and Pco2 related to fluid migration and subsurface mixing are evidently the controlling variables. Carbon and oxygen stable isotope data are compatible with dolomite precipitation from largely non-marine fluids containing organically sourced carbon species. Systematic lithological, spatial, depth and/or thermally related patterns of diagenetic modification are recognized on a basin-wide scale. In view of the significant role diagenetic processes have played in the evolution of hydrocarbon reservoirs, an understanding of their relationship to fluid migration and organic maturation is important to future exploration. In conjunction with knowledge of basin tectonics, thermal and sedimentological history, this understanding is fundamental to developing models which predict porosity trends and reservoir quality in the Gippsland and other sedimentary basins.
THE SHOWGROUNDS FORMATION, ITS SETTING AND SEAL, IN ATP 145P, QLD
Authors: Butcher P. M.
Published: August 2017

The Middle Triassic Showgrounds Formation is the major reservoir in the permit ATP 145P, situated on the western flank of the Mimosa Syncline of the Surat Basin and including the Roma Shelf and Wunger Ridge. Proven and probable reserves stand at 2 billion cubic metres (70 billion cubic feet) of gas and 635 000 kilolitres (4 million barrels) of liquid hydrocarbons.The Showgrounds Formation lies directly on either the Lower Triassic Rewan Formation, the Upper Permian Kianga Formation or older Palaeozoic rocks. The underlying lithology and palaeotopography contribute to the nature and distribution of the Showgrounds Formation. Source rock potential in the Permian Kianga and Back Creek Formations is very good, but good Permian reservoirs are lacking. The Rewan Formation, where present in the eastern half of the permit, acts as a barrier to the vertical migration of hydrocarbons from the Permian source.Although the Showgrounds Formation is widespread, it is not homogeneous and exhibits pronounced lateral variation. It can be subdivided, on the basis of vertical profiles seen in cores and on log character, into three major facies of fluvial origin, one of which shows evidence of marine modification in a deltaic environment. Reservoir qualities vary considerably in each facies but are best developed in the proximal fluvial facies. This facies exhibits high porosities and permeabilities, with secondary porosity developed by dissolution of carbonates and flushing of clays being an important feature. This sequence is ideally situated to trap westerly migrating hydrocarbons, since it is situated west of the Rewan Formation pinchout. The widespread marginal marine to marine Sub-Unit 9 shale, always present above the Showgrounds Formation, provides the seal. The typical trapping mechanism is a combination of structural and stratigraphic components.
A SEISMIC MODEL OF FAULTS IN THE COOPER BASIN
Authors: Gray R. J. , Roberts D. C.
Published: August 2017

A synthetic seismic section was modelled to help in the interpretation of Cooper Basin seismic lines which cross major faults and exhibit shadow zones.A major fault bounding the northwest flank of the Packsaddle Structure in the Merrimelia-Innamincka Farmout Block in South Australia was selected for modelling. A geological cross-section postulated on the basis of wells on either side of the fault was fed into the seismic modelling package AIMS (Advanced Interpretive Modelling System — licensed by Geoquest International Inc.) to produce a synthetic seismic line. This synthetic line provided a realistic match with an actual seismic line across the fault. Pre-stack migration of the actual seismic data is suggested to provide additional evidence for the reliability of the model.The shadow zone in the synthetic section is caused by dipping events in the fault shadow zone created by compaction of the Toolachee and Patchawarra Formations along the hanging wall of the fault plane. The dipping events cause reflected energy to be detected outside the fault zone. The large component of compaction within the Permian section is largely ascribed to thick coal horizons. The possibility of petroleum traps in the hanging wall of the fault is inferred and drilling is recommended.
PRACTICAL USE OF BOREHOLE SEISMIC IN EXPLORATION
Authors: Nutt F. Sandnes W. L. , Henry S. G.
Published: August 2017

The improvement of acquisition and processing techniques has made it possible to study seismic wavetrains in boreholes.With careful acquisition procedures and quantitative data processing, one can extract useful information on the propagation of seismic events through the earth, on generation of multiples and on the different reflections coming from horizons that may not all be accessible by surface seismic.An extensive borehole seismic survey was conducted in a well in Conoco's contract area 'Block B' in the South China Sea. Shots at 96 levels were recorded, and the resulting Vertical Seismic Profile (VSP) was carefully processed and analyzed together with the Synthetic Seismogram (Geogram*) and the Synthetic Vertical Seismic Profile (Synthetic VSP).In addition to the general interpretation of the VSP data, i.e. time calibration of surface seismic, fault identification, VSP trace inversion and VSP Direct Signal Analysis, the practical inclusion of VSP data in the reprocessing of surface seismic data was studied. Conclusions that can be drawn are that deconvolution of surface seismic data using VSP data must be carefully approached and that VSP can be successfully used to examine phase relationships in seismic data.
INTERNATIONAL PETROLEUM INVESTMENT — WHY AUSTRALIA?
Authors: Patterson J.C.
Published: August 2017

This paper presents the methodology that Conoco, a major international energy company, uses to make exploration investment decisions. This methodology includes a detailed and well coordinated analysis of the technical merits, cost environment, political/economic environment, and contract terms for every area of interest.Conoco continually monitors the activity in the more than 500 sedimentary basins around the world. A forecast of undiscovered reserves is made by country and basin. Obviously, all else being equal, it is better to search for oil in places considered to have the most oil left to be discovered. Gas prone areas tend to be of less interest.Once an area is identified to be of interest, data are collected on specific identifiable prospects to begin an exhaustive analysis. Recoverable reserves are estimated and the exploration program required to evaluate the area is determined.The development costs for the anticipated discovery are estimated along with production profiles. Sensitivity analyses are performed to view the effects of delays caused by factors beyond operator control.The political/economic environment in which operations would function is evaluated. A company must be able to anticipate that a government with stability and integrity will reign throughout the life of a project.Finally, the contract terms that govern the petroleum operations are analyzed. A complete discounted cash flow analysis is performed.This paper considers how each of these elements in the analysis might be a plus or a minus with regard to directing exploration funds toward Australia and shows that Australia affords an ideal mix of technical/geological merit with a workable acquisition environment and attractive economic reward. Comparisons will be made with other areas around the world.
THE PETROLEUM PROSPECTIVITY OF THE CLARENCE-MORETON BASIN IN NEW SOUTH WALES
Authors: Ties P. , Shaw R.D. , Geary G.C.
Published: August 2017

The Clarence-Moreton Basin covers an area of some 28 000 km2 in north-eastern New South Wales and south-eastern Queensland. The basin is relatively unexplored, with a well density in New South Wales of one per 1600 km2. Since 1980, Endeavour Resources and its co-venturers have pursued an active exploration programme which has resulted in the recognition of significant petroleum potential in the New South Wales portion of the basin.Previous studies indicated that the Upper Triassic to Lower Cretaceous Clarence-Moreton Basin sequence in general, lacked suitable reservoirs and had poor source- rock potential. While exinite rich, oil-prone source rocks were recognised in the Middle Jurassic Walloon Coal Measures, they were considered immature for oil generation. Moreover, during the 1960's the basin acquired a reputation as an area where seismic records were of poor quality.These ideas are now challenged following the results of a new round of exploration which commenced in the New South Wales portion of the basin in 1980. This exploration has involved the acquisition of over 1000 km of multifold seismic data, the reprocessing of some 200 km of existing single fold data, and the drilling of one wildcat well. Over twenty large structural leads have been identified, involving trapping mechanisms ranging from simple drape to antithetic and synthetic fault blocks associated with normal and reverse fault dependent and independent closures.The primary exploration targets in the Clarence- Moreton Basin sequence are Lower Jurassic sediments comprising a thick, porous and permeable sandstone unit in the Bundamba Group, and channel and point-bar sands in the Marburg Formation. Source rocks in these and the underlying Triassic coal measures are gas-prone and lie at maturity levels compatible with gas generation. In contrast, it was established from the results of Shannon 1 that the Walloon Coal Measures are mature for oil generation and this maturity regime is now considered to be applicable to most of the basin in New South Wales.A consideration of reservoir and source rock distribution, together with structural trends across the basin in Petroleum Exploration Licences 258 and 259, has led to the identification of three prospective fairways, two of which involve shallow oil plays. Exploration of these fairways is currently the focus of an ongoing programme of further seismic data acquisition and drilling.
GAS LIFT IN BASS STRAIT
Authors: Fagg Kathryn J.
Published: August 2017

Gas lift has proved a most effective artificial lift method for the fields operated by Esso Australia Ltd in Bass Strait for the Esso-BHP joint venture. Gas lift is now used to produce approximately 5 st ML/d of the total crude production from the Strait. It has enabled wells to be produced to water cuts higher than 90 per cent, increasing the oil recovery from the fields by up to 35 per cent.Gas lift work in Bass Strait to date has included the use of special packoff gas lift assemblies for wells with sliding sleeves, the development of a tool to assist the opening of the sleeves, improved operating techniques to limit slugging from gas-lifted wells, and the testing of gas lift performance. Gas lifting has been more successful than expected, and as a result, workovers initially planned to install full gas lift strings for older wells have not been necessary. The two phase flow correlations available have been improved to match the performance of the gas-lifted wells. The correlations are now used to design tubing strings with a number of gas lift mandrels prior to running the initial completions and to select the optimum gas injection depth.Future work in gas lift for Bass Strait will involve the optimisation and automation of lift gas distribution on the platforms. Gas lift will also be used for planned future developments, including mini-platforms and subsea completions.
BASS STRAIT WATER HANDLING DEVELOPMENTS
Authors: Hayes John J.
Published: August 2017

Esso Australia Ltd operates, on behalf of Esso/BHP, a crude oil and natural gas producing and processing facility in the Gippsland Basin, Victoria. Saline formation water produced with the oil is treated and discharged overboard from offshore platforms wherever possible to limit the volume of saline water in the pipeline system and avoid onshore disposal of saline water. Esso has developed oily water treatment and continuous oil-in- water monitoring beyond conventional technology and operates within stringent overboard water discharge regulations. Initial oily water treating installations were Cross Flow Interceptors, a corrugated plate gravity separator. Unsatisfactory performance prompted investigations leading to development of the Dissolved Gas Flotation unit using evolved gas to lift oil droplets to the surface. These units operate successfully offshore today. The most recent developments have been associated with a liquid-liquid hydrocyclone trade named 'Vortoil'. This has been tested offshore with an 'Purometer' continuous oil-in-water monitor. The Vortoil and Purometer have both performed favourably and proven a compact, low cost combination for future water treating installations.
USE OF DRAG REDUCER CHEMICAL IN THE BASS STRAIT CRUDE OIL PRODUCING SYSTEM
Authors: Wilmshurst Jan
Published: August 2017

Esso Australia Ltd (on behalf of the Esso/BHP joint venture) operates a crude oil and natural gas processing system based on the offshore fields in Bass Strait.Crude oil is discharged from the offshore fields via a 132-km pipeline to the crude stabilization plant at Longford. A 187-km pipeline is then used to transfer stabilized crude to Long Island Point, where the oil is held in storage prior to discharge to Australian refineries and to export.Without the use of drag reducer chemical, Bass Strait crude production is limited by pipeline hydraulic capacity. Since the last quarter of 1983, drag reducer has been injected at both Halibut platform and Longford as required to meet the demand for crude oil. As a result, daily production rates have been increased by more than ten per cent.Drag reducer chemical is a long chain polymer which acts to reduce the extent of turbulence in the flowing oil stream. The chemical is highly viscous, and specifically designed gear pumps are required to achieve satisfactory injection into the pipeline systems.
CONVERSION OF GAS TO TRANSPORTATION FUELS
Authors: Partridge W.R.
Published: August 2017

There is a widespread interest in the utilisation of the world's gas reserves, a considerable volume of which are located in remote areas and cannot be transported economically by pipeline. In addition the traditional market for such gas has been liquefied natural gas, but currently the market appears to be saturated. Consequently Bechtel Petroleum Inc. made a technical and economic analysis of processes which could be used to convert natural gas to transportation fuels. It was found that there is a number of new technologies which could be considered commercial and a considerable number that look promising but are not yet commercial.This paper presents the results of the economic analysis of the following five commercial or near commercial processes.Natural gas to methanol,Natural gas to methanol and gasoline,Natural gas to gasoline and diesel via the Fischer Tropsch process,Natural gas to gasoline and distillate (via extracted liquified petroleum gas), andOlefins direct to gasoline and distillate.For comparison purposes the economics of liquified natural gas were also developed.This comparison indicated that the conversion of olefins to transport fuels has a distinct economic advantage over the others. In addition this process has the flexibility of yielding varying percentages of gasoline and diesel according to market demand whereas some of the processes can produce only a single product. One disadvantage is that the olefins feedstock must be priced on a heating value basis comparable to natural gas and not for its alternative value in the manufacture of petrochemicals. There are situations in the world where refinery and chemical offgases containing olefins in dilute form could be priced competitively with natural gas.The conversion of extracted liquified petroleum gas from natural gas also looks promising, but it must be priced competitively with natural gas.The economic comparison highlighted the need for future basic research into the conversion of natural gas directly to transportation fuels rather than going through intermediate steps. Considerable research is currently being directed to these conversion processes. In addition there is also research being conducted to improve the economics of the commercial Fischer Tropsch conversion process.
RECENT EXPLORATION AND HYDROCARBON POTENTIAL OF THE ROMA SHELF, QUEENSLAND
Authors: Cosgrove J.L. , Mogg W.G.
Published: August 2017

The probability of finding additional gas reserves on the Roma Shelf within Authority to Prospect 336P and Petroleum Leases 3-13 is assessed as being very high. There is a 50 per cent probability that 80 billion cubic feet (2250 million cubic metres) will be found and a 20 per cent probability that 290 billion cubic feet (8170 million cubic metres) will be discovered.Recent seismic information together with geologic models developed for the Roma Shelf, Queensland have refined the settings of various plays of this important hydrocarbon province. Despite the large number of wells drilled in the region, it is still relatively unexplored considering the small size of economic accumulations and when compared to other sedimentary basins containing similar play types, elsewhere in the world.Modern regional seismic coverage has lead to an improved understanding of the basin's structural history. Tectonic events such as strike-slip faulting and compression commencing in the Early Carboniferous and continuing into the Tertiary have formed several structural traps in the area.Recognition of the importance of reservoir horizons such as the Lower Triassic Rewan Formation and the Upper Permian Tinowon Formation has added to the prospectivity of this area.Recent exploration has been highly successful with 67 per cent of the exploration drilling resulting in new field discoveries. This success rate has stemmed from finer spaced grids of high resolution seismic which has provided accurate prospect mapping. Refinements to exploration concepts have also resulted from an integrated geological and geophysical approach.
THE GEOLOGY AND EVOLUTION OF THE SOUTH PEPPER HYDROCARBON ACCUMULATION
Authors: Williams A.F. , Poynton D.J.
Published: August 2017

The South Pepper field, discovered in 1982, is located 30 km southwest of Barrow Island in the offshore portion of the Barrow Sub-basin, Western Australia. The oil and gas accumulation occurs in the uppermost sands of the Lower Cretaceous Barrow Group and the overlying low permeability Mardie Greensand Member of the Muderong Shale.The hydrocarbons are trapped in one of several fault closed anticlines which lie on a high trend that includes the North Herald, Pepper and Barrow Island structures. This trend is postulated to have formed during the late Valanginian as the result of differential compaction and drape over a buried submarine fan sequence. During the Turonian the trend acted as a locus for folding induced by right-lateral wrenching along the sub-basin edge. Concurrent normal faulting dissected the fold into a number of smaller anticlines. This essentially compressional tectonic phase contrasted with the earlier extensional regime which was associated with rift development during the Callovian. A compressional tectonic event in the Middle Miocene produced apparent reverse movement on the South Pepper Fault but only minor changes to the structural closure.Geochemical and structural evidence indicates at least two periods of hydrocarbon migration into the top Barrow Group - Mardie Greensand reservoir. The earlier occurred in the Turonian subsequent to the period of wrench tectonics and involved the migration of oil from Lower Jurassic Dingo Claystone source rocks up the South Pepper Fault. This oil was biodegraded before the second episode of migration occurred after the Middle Miocene tectonism. The later oil is believed to have been sourced by the Middle to Upper Jurassic Dingo Claystone. Biodegradation at this stage ceased or became insignificant due to temperature increase and reduction of meteoric water flow. Gas-condensate, sourced from Triassic or Lower Jurassic sediments may have migrated into the structure with this second oil although a more recent migration cannot be ruled out.The proposed structural and hydrocarbon migration history fits regional as well as local geological observations for the Barrow Sub-basin. Further data particularly from older sections of the stratigraphic column within the area are needed to refine the interpretation.
LEGAL AND TAXATION IMPLICATIONS FOR THE ACQUISITION AND DISPOSAL OF OFFSHORE PETROLEUM PRODUCTION AND EXPLORATION TENEMENTS—A PRACTICAL VIEW AND UPDATE
Authors: Allen J. , Williamson M.
Published: August 2017

The administrative aspects of petroleum mining and exploration companies have become more complex of recent years. One area where this is particularly so is in relation to the livelihood of the industry, i.e. access to tenements.While exploration and development activity onshore has hotted up in particular, offshore activity has been fervent but limited largely to bringing into production fields on the North West Shelf, at Jabiru and new areas in Bass Strait. Generally it is held that the likelihood for discoveries of large fields will be offshore Australia rather than onshore and that present exploration activities offshore are inadequate to maintain Australia's oil self-sufficiency.Recent amendments to the Petroleum (Submerged Lands) Act, a plethora of associated Acts, and proposed new tax imposts (e.g. cash bonus bids, retention licence fees, resource rent tax, and capital gains tax) in relation to the offshore segment of the industry have added significantly to the complexities in planning the acquisition and disposal and ongoing control of tenements. Each of these is examined individually and in conjunction for the benefit of planners and executives administering tenements within their organisations.Both sides of the transaction are viewed with emphasis on their tax positions providing opportunities to control the directions and funding mechanisms for the transaction.
CAPITAL GAINS TAX IN THE PETROLEUM INDUSTRY
Authors: Breckenridge S.
Published: August 2017

Eleven years after a previous abortive attempt, another Federal Labor Government has announced its intention to incorporate into the Australian fiscal scene a capital gains tax. The tax is to be levied at marginal and corporate income tax rates on 100 per cent of inflation adjusted gains realised on assets acquired on and after 20 September 1985.Whilst the Government expects its revenue yield to be low even at the end of five years of operation, the cost of protective administration and compliance to be incurred by taxpayers will be substantial.There are substantial areas of uncertainty in the capital gains tax proposals generally, and in particular as they relate to the petroleum industry. These issues, coupled with the prospect of significant legislative delay, will detract further from Australia's appeal as a focal point for essential exploration dollars.The capital gains tax proposals outlined to date deal, superficially, with basic and very tangible property. However, they do not come to grips with issues such as the potential duplication of this tax and resource rent tax, the need to protect the position of non-residents from double taxation, the basis for imposition of capital gains tax upon changes in licence and permit interest through direct or indirect transfers, to avoid bunching distortions, and to more fully provide for rollover relief.The capital gains tax proposals will exacerbate the substantial stress upon the Australian Taxation Office and, coupled with the forthcoming requirement of the Income Tax Assessment Act to accommodate the proposed resource rent tax, will only serve to highlight the fact that in reality the petroleum industry has not been a winner in this area of the tax reform process.The scope for unexpected capital gains tax exposures to arise is marked and will require a clear analysis of several long-established legal concepts to ensure that even reasonable results are obtained.
RECENT CHANGES TO AUSTRALIA'S OFFSHORE PETROLEUM REGIME
Authors: Reid P.C.
Published: August 2017

Australia's offshore petroleum legislation is the product of a constitutional compromise enshrined in the Offshore Constitutional Settlement of 1979 between the Commonwealth and the States. Whilst it is current Federal Australian Labor Party policy to dismantle the Offshore Constitutional Settlement and re-assert exclusive Commonwealth jurisdiction from the low-water mark seawards, the Hawke Labor Government has been reluctant to implement this particular policy.A practical consequence of the Offshore Constitutional Settlement for the industry is that many offshore titles are now being split into two separate titles — one under State legislation within the three-mile territorial sea and the other under Commonwealth legislation for the Adjacent Area beyond the territorial sea. The Commonwealth proposal to introduce cash bonus bidding for highly prospective offshore exploration permits after being defeated in the Senate in the first half of 1985 was subsequently passed in November 1985.An APEA proposal for the introduction of a new form of title under the Petroleum (Submerged Lands) Act (PSLA) to protect currently non-commercial reserves has been adopted by legislation.Following the cash bidding debate the Commonwealth Minister has proposed a new set of guidelines for the award of offshore permits which will contain both a fixed dry-hole commitment plus a discretionary program in the event of technical encouragement.The paper concludes with some recommendations for establishing a more secure and certain system of title under the PSLA and to minimize the current administrative delays being experienced by industry. Finally it urges that the current level of consultation between Government and industry on matters of interest arising under the PSLA should be allowed to continue.
THE AUSTRALIAN OIL INDUSTRY — TWO YEARS OF FLOOD BEFORE THE PERMANENT DROUGHT
Authors: Story I.
Published: August 2017

World oil intensities have undergone a fundamental change since 1976, when gross domestic product growth outstripped oil consumption for the first time. World oil demand has fallen each year since 1979 irrespective of economic conditions.International supply management is the only way of containing oil price falls. In the longer term, non-OPEC production will peak by the end of this decade because there have been no major developments since the mid-1970's. Prices are likely to rise again as supply from non-OPEC countries falls, allowing OPEC to reassert market control.Australia has achieved 100 per cent self-sufficiency in crude oil, but a substantial increase in exploration activity is required if a major fall in self-sufficiency is to be averted after Bass Strait peaks in 1987. Browse Basin (Timor Sea) disappointments indicate that while there will be good production from Jabiru and perhaps Challis, these will not replace the declining Mackerel, Halibut, and Kingfish fields in Bass Strait.The Cooper/Eromanga Basin, while highly prospective, will never produce the quantities needed to replace Bass Strait. Jackson's reserves are estimated at about 45 million barrels. By comparison, Mackerel and Halibut together will produce 58 million barrels in 1985-86 alone.If oil is not found the balance of payments will suffer badly. Each percentage point drop in self sufficiency will cost Australia $85 million or nearly 0.5 per cent of exports. If domestic production falls to 470 000 barrels per day by 1990, imports of crude oil will cost $2 billion in 1985 dollars (assuming flat oil prices). Expressed in another way, 6 per cent of Australia's exports will be required to pay for the incremental drop in self-sufficiency by 1990.In 1984-85 the Government took in $4.26 billion from the crude oil levy, almost exclusively from Bass Strait. In 1985-86 the Government will receive $4.7 billion. This represents 8.7 per cent of Government taxation revenue, and 8 per cent of total Government receipts. By 1990, the levy from Bass Strait will fall by 45 per cent (assuming a constant oil price). By 1995 the revenue will be 90 per cent less than 1985-86, posing a major budgetary funding problem.
TAXATION ASPECTS OF SOLE RISK, OR, HOW TO MAKE THE TAX SYSTEM WORK FOR YOU
Authors: Wilson P.A.
Published: August 2017

Two of the problems currently facing the petroleum industry are the cost of funding petroleum and the relatively few major discoveries. Without major discoveries it is difficult, and will become more difficult, to attract new money into the petroleum exploration business.With these factors in mind it becomes more necessary for few companies to spend more money to fund major exploration programs and for the costs to be adequately shared by all participants in a venture.As currently drafted, the sole-risk provision in a Joint Operating Agreement acts as a rationer of scarce resources (i.e. money) for the finding of major new reservoirs. However, by restructuring the sole-risk premium clause it is possible to increase the financial cost (through income tax, resource rent tax, or resource rent royalty, as applicable) upon a party allowing another party to conduct a sole-risk project. This increased penalty might be a major factor in reducing the incidence of sole-risk programs without reducing the number of programs brought forward outside of permit work programs commitments.To achieve this end the sole-risk clause should be restructured to require the sole-risk party to own the project (information, wells, completion, deepening, etc) and then for it to create undivided interests on the sole-risk project for disposal to the non-sole-risk party. In this way, the premium would be received as consideration on sale of an interest in the project and not a disproportionate allocation of product.If this restructure were conducted then the interaction of income tax, and where applicable resource rent tax and resource rent royalty, might well induce all parties to agree to participate in non-work program operations leaving all work programs subject to sharing.
DEPOSITIONAL ENVIRONMENTS AND HYDROCARBON POTENTIAL OF THE EVERGREEN FORMATION, ATP 145P, SURAT BASIN, QUEENSLAND
Authors: Golin V. , Smyth M.
Published: August 2017

Hydrocarbon discoveries in the Jurassic Evergreen Formation along the western shelf of the Surat Basin lie in a northwest-trending structurally controlled belt adjacent to Bridge-operated ATP 145P. Shows and commercial accumulations are generally associated with specific sand/shale ratios, which influence source, reservoir, and seal effectiveness. Proximity to basement and early faults are other favourable factors.Four distinct log facies were calibrated against cuttings and core and interpreted genetically. Small, stream-dominated alluvial-fan systems extended from low escarpments in the west, but were reworked along their basinward margins prior to being overstepped by aggradational, onlapping distal sediments. Prominent east-northeast-trending belts occupied by mixed-load fluvial channel systems terminated along a temporary shoreline of coalescing wave-dominated deltas. This deltaic-shore-zone sand belt was truncated by fluvial-distributary channels during the ensuing regression to another still-stand some 25 km farther east. Shoreline positions fluctuated locally in response to competition between rate of sediment influx and the gradually rising base level; but the net effect was regional transgression, with reworked shorezone/nearshore sheetsands grading up into silty shales of the shallow epeiric platform.On the basis of a petrographic study the highest source potential for the Evergreen Formation in ATP 145P is around Spring Grove 1 well. A band of high source potential lies parallel to the deltaic shoreline, in a generally north-south direction. The highest source potential of the Triassic Moolayember Formation lies around Spring Grove 1 and in a north-south trending arc through Roswin 1 and Sirrah 4. The source potential of the combined Triassic Snake Creek Member, Showgrounds and (Permian) Kianga formations is highest around Roswin 1. In the area of Roswin 1 all formations studied show a high potential as source rocks for hydrocarbons. Based on the available data, the Triassic Moolayember Formation appears to be the only formation common to all producing wells with a high source potential in each well.Zones of thick, porous sands are not very prospective for hydrocarbons in the study area, possibly because of ineffective seal. True shales are rare in the Evergreen Formation. The dominant fine-grained lithology is silt-stone, which by itself provides a leaky or dynamic seal at best. Thin, reworked delta mouth bar and splay sands with thick seals may offer the best reservoir objectives. Known hydrocarbons generally occur in structural-strati-graphic traps with the structural component caused by compaction and subsequent draping over basement topography, and the stratigraphic component arising from the lenticularity of the fluvio-deltaic sand bodies.
EVALUATION OF FORMATION PROPERTIES FROM PROCESSING AND INTERPRETATION OF THE EVA TOOL LOGS
Authors: Arditty P. C. , Mathieu F. , Staron P.
Published: August 2017

With the development of full waveform acoustic tools, geophysicists have tried to extract more and more information from acoustic parameters and to relate to the data to formation propertiesThe new tool, EVA (Evaluation of Velocity and Attenuation), is a 4-transmitter/12-receiver long spacing tool permitting recording of the complete waveform and processing of all information contained in the acoustic signal.The key point for optimum results is a robust and automatic processing which allows quantitative estimation of different parameters such as velocity, amplitude, and period of all the three main types of waves, i.e. compressional (P), shear (S), and Stoneley (ST) waves.In parallel with the processing phase, the analysis of the raw data leads to a qualitative and very rapid interpretation of the recordings.Once the processing is completed and all parameters obtained, these may be applied to a quantitative interpretation of the EVA data. Such interpretation can then be utilised for automatic lithology estimation, estimation of porosity and shale content, and to the detection of fractures and eventually the estimation of permeability.Further applications such as the detection of invaded zones, estimation behind casing, estimation of elastic moduli, and the reconstitution of a density log can provide significant data for exploration and production engineers.
A THIN SKINNED MODEL FOR THE PAPUAN THRUST BELT AND SOME IMPLICATIONS FOR HYDROCARBON EXPLORATION
Authors: Hobson D.M.
Published: August 2017

In the Papuan thrust belt the main risk in hydrocarbon exploration lies in identifying structural traps which are detached below the level of the primary reservoir. Because of the difficulty in obtaining usable seismic in the remote, inaccessible terrain, identification of prospects has been based on the interpretation of structural cross-sections drawn from geological maps. The structural models commonly used have been geometrically inadmissible, and as a result, some wells have penetrated thrusts at depth, before reaching the reservoir horizon.More rigorously constrained regional cross sections through the thrust belt may be constructed using the principles of thin skinned tectonics. These may be used to identify structural provinces, characterised by different types of thrust pattern. In turn, the probability of reservoir involvement in a particular structure is directly related to its location in a particular province.The cross-sections show that there has been as much as 100 km of shortening in the hinterland of the thrust belt. Restored versions of the cross sections may be used to reconstruct the shape of the basin and ideally to identify regions favourable for source and reservoir sediment distribution. In Papua New Guinea, palinspastic maps are currently feasible only for Miocene strata, but with the present level of exploration activity increased stratigraphic information should soon permit reconstructions for older formations.
THE USE OF VSP TECHNIQUES IN FIELD EVALUATION
Authors: Ireson R.L.
Published: August 2017

Vertical Seismic Profiling (VSP) techniques have been developed which have found application in the development and production of hydrocarbons as well as in exploration.A VSP is initiated by outlining the objectives of the survey and, using a model of the geology in the vicinity of the borehole, applying inversion techniques to determine the VSP method best suited to provide the required data. Reflection coverage, critical refractions, and mode conversion data (using 3-component geophones) can be used to obtain a structural, lithologic, and petrophysical interpretation.Structural interpretations using recently developed migration techniques based on the scalar wave equation can now provide images of the sub-surface which are superior to those obtained using previous ray-trace schemes.Acoustic impedance estimates from VSP surveys processed with deterministic deconvolution techniques and optimal amplitude recovery to obtain maximum temporal resolution can be more accurate than those obtained from surface seismic data. Offset VSP data can also give an estimate of reservoir porosity variations away from the borehole.
THE GEOLOGY AND HYDROCARBON POTENTIAL OF THE EP 104 PERMIT, NORTHWEST CANNING BASIN, WESTERN AUSTRALIA
Authors: Lehmann P.R.
Published: August 2017

Current interpretations suggest the presence of five Devonian reef building cycles in EP 104 with a further two in the Ordovician, Nita, and Willara formations. The possible Devonian reefs occur in the NVorral, Lower and Upper Pillara, Virgin Hills, and Nullara carbonate cycles. Minor buildups may be present in the Fairfield and Laurel formations.The Upper Pillara reef complex was subaerially exposed and partly eroded for a period of 10 to 50 million years, following the Early Frasnian 'Tappers Inlet orogeny'. Large potential hydrocarbon reservoirs were created by the secondary mega-porosity formed during this period, and these were sealed by the regional Laurel transgression in the Early Carboniferous. This mode of porosity enhancement is applicable to all the potential reef cycles, as varying degrees of unconformity mark their upper boundaries, generally followed by onlap of sealing lithologies. The Upper Pillara cycle is considered the most prospective of the Devonian carbonate cycles which were the main targets in the first five wells.In response to the success of Home Energy Co. Ltd at Sundown, the last four wells in EP 104 have had Permo-Carboniferous objectives. This drilling resulted in the discovery in 1982 of the small Kora oilfield, believed to have been sourced from the Laurel Formation.The Black Rocks Prospect, in King Sound, is being considered for the first 1986 exploration well. This represents a return to Devonian Pillara reefs, the traditional primary targets in EP 104. As a bonus, drape, accentuated by late collapse of the reefal core, has localized multiple Permo-Carboniferous structural closures, coincident with reefal closure.By comparison with the highly productive Swan Hills and Rainbow-Keg River reefs in Canada the Pillara and Worral carbonate cycles in EP 104 must have considerable potential.