bluuebunny/crossref_metadata_2025 huggingface dataset:
THE COBIA 2 SUBSEA COMPLETION
Authors: Shaw M. N.
Published: August 2017

Subsea completions are recognised worldwide as a cost effective means of developing marginal reservoirs, accelerating production and draining reservoir extremities which cannot be reached from conventional platforms. To date, more than 280 subsea completions have been installed around the world. Cobia 2, the first subsea completion in Australian waters, commenced production in Bass Strait in June 1979. It continued to produce until April 1983, when it was shut-in following the commencement of production from the Cobia platform. In its four years of operation, the well produced over 280 megalitres (1.78 million barrels) of crude oil, with peak well rates reaching as high as 750 kilolitres per day in the latter stages of its producing life. Overall, Cobia 2 has been a technical and commercial success.The need for regular pumpdown or TFL ('through flowlines') wax-cutting operations in the flowlines to maintain high levels of production generated a great deal of confidence in the use of TFL techniques for routine and non-standard subsea well servicing. In an industry 'first', TFL methods were developed to lock open and seal a leaking subsurface safety valve and, within it, set a special insert subsurface safety valve. This work allowed the well to be returned to production in a situation where a conventional workover of the well was not feasible.Other well-servicing techniques developed during the Cobia 2 project involved the novel use of a coiled tubing unit to retrieve TFL tools which had become stuck in the flowlines during the wax-cutting operations.The highly successful operation of Cobia 2 has proved the viability of this type of completion for marginal field development in Australia.
RESERVOIR SIMULATION OF THE GIPPSLAND BASIN
Authors: Khurana S. T. Henzcll A. A Young A K.
Published: August 2017

A three-dimensional, single-phase reservoir simulation model of the entire Gippsland Basin aquifer system, together with its oil and gas reservoirs, was first developed in 1973. It was replaced by an improved version in 1975. Now, after fifteen years of production, pressure predictions from the model still compare very well with data obtained from current exploration and development wells.The model, consisting of 4186 grid blocks, incorporates the geological description, and pressure and fluid distribution of the basin. The geological description includes porosity, net-to-gross ratio and permeability with fluid properties representing the aquifer. A well-established initial pressure/depth relationship for the Gippsland Basin is included in the model. Although it is a single-phase model, oil and gas reservoirs are represented by pseudo rock and fluid properties.The model is regularly updated with historical and forecast production rates in order to predict pressure behaviour and therefore aquifer strength in various areal and stratigraphic locations in the basin. Such information is essential for defining external boundary conditions in individual reservoir simulation models and assists in gas deliverability forecasts. In exploration wells, measured pressures are compared with model predictions to help understand the degree of pressure communication with the basin aquifer and hence the level of pressure support. Detailed predictions of the pressure gradients expected in both exploration and development wells are often of assistance in identifying fluid contacts, overpressure and reservoirs with limited communication with the aquifer.
THE USE OF GAS ISOTOPES IN DETERMINING THE SOURCE OF SOME GIPPSLAND BASIN OILS
Authors: James B. J. Burns A. T. , Emmett J.K.
Published: August 2017

The technique of determining the level of maturity of a gas by using the isotopic separation between its hydrocarbon components has been applied to gases flashed from undersaturated Gippsland Basin oils. The results suggest that the Gippsland Basin oils have been generated at an LOM of 11-12. Fluviatile shales of Late Cretaceous age at depths of around 3900 m are interpreted as being the source for much of the paraffinic oil discovered to date.
GEOLOGY OF THE JACKSON OIL FIELD
Authors: Halyburton R. V. , Robertson A. L.
Published: August 2017

The Jackson oil field was discovered late in 1981 with the drilling of Jackson 1, which was programmed as an exploration well designed to test the Jurassic-Cretaceous Eromanga Basin sequence and the Permian Cooper Basin sequence, if present. The well tested oil from three formations.The first test to produce oil was carried out across a sand in the Early Cretaceous Murta Member of the Mooga Formation. The zone produced 47° API gravity oil at the rate of 338 barrels (53.7 kilolitres) of oil per day. This was followed by two tests which produced 41° API gravity oil at the rates of 188 and 1165 barrels (29.9 and 185.2 kilolitres) per day respectively from thin sands in the Late Jurassic Westbourne Formation. As a fitting conclusion, the well intersected a 100ft (30 m) oil-saturated section in the Jurassic Hutton Sandstone which on testing flowed 41° API gravity oil at a maximum rate of 2616 barrels (415.9 kilolitres) per day.Four appraisal wells subsequently drilled in the Jackson Field confirmed the initial belief that development of the field was a viable proposition.Compared to the Hutton and Westbourne accumulations, the size of the Murta accumulation is relatively insignificant. The accumulation in the Murta is primarily controlled by structure. On the other hand, the Westbourne accumulation appears to have a strong component of stratigraphic control. In the Hutton accumulation, there is a fair amount of variation in the geometry of the sand bodies at the top of the reservoirs. The accumulation is, however, dominantly controlled by structure.
DEFOSITIONAL FRAMEWORK AND DIAGENESIS OF THE LATE PERMIAN GAS RESERVOIRS OF THE BONAPARTE BASIN
Authors: Bhatia M. R. , Thomas M. , Boirie J.  M.
Published: August 2017

Late Permian sandstones form the reservoir of the Tern and Petrel gas fields in the offshore Bonaparte Basin. The producing reservoirs of the Petrel field were deposited in various environments associated with a major northwesterly trending deltaic system. The producing sands in the Tern field were deposited in the shoreface environment of a barrier-bar system.The reservoir quality of the sands is controlled by the diagenesis, which is facies dependent. In the Petrel field, sandstones deposited in the upper delta plain and along the shoreline are clean, medium-to coarse-grained and highly quartzose but have very low porosity and permeability due to extensive quartz diagenesis. However, sands deposited in delta front and lower delta plain environments are medium to fine grained, argillaceous and have fair to good reservoir potential. In these sands, the dispersed clays formed coats and rims on quartz grains during early diagenesis and inhibited quartz overgrowth. In the Tern field, sands of the upper shoreface have poor reservoir quality due to early calcite cementation. However, finer-grained sandstones of the lower shoreface facies have good reservoir quality. The porosity in these sands is mainly primary and preserved due to low carbonate and high clay content. The processes of quartz and calcite cementation which drastically reduced the reservoir quality of the coarse-grained sands occurred early and were influenced by the texture of the sands and probably also by the chemical character of the formation waters.
THE STRUCTURAL DEVELOPMENT AND HYDROCARBON POTENTIAL OF PALAEOZOIC SOURCE ROCKS IN THE ADAVALE BASIN REGION
Authors: Passmore V. L. , Sexton M. J.
Published: August 2017

The Adavale Basin of southwestern Queensland consists of a main depression and several isolated synclinal extensions, traditionally referred to as troughs. The depressions and troughs are erosional remnants of a once more extensive Devonian depositional basin, and are now completely buried by sediments of the overlying Cooper, Galilee and Eromanga Basins. Geophysical and drilling investigations undertaken since 1959 are the only source of information on the Adavale Basin. A single sub-economic discovery of dry gas at Gilmore and a few shows of oil and gas are the only hydrocarbons located in the basin to date.In 1980, the Bureau of Mineral Resources in cooperation with the Geological Survey of Queensland commenced a major, multidisciplinary investigation of the basins in southwestern Queensland. Four long (> 200 km) seismic lines from this study over the Adavale Basin region and geochemical data from 20 wells were used to interpret the Adavale Basin's development and its present hydrocarbon potential.The new seismic reflection data allow the well-explored main depression to be correlated with the detached troughs, some of which have little or no well information. The BMR seismic data show that these troughs were previously part of one large depositional basin in the Devonian, the depocentre of which lay east of a north-trending hingeline. Structural features and Devonian depositional limits and patterns have been modified from earlier interpretations as a result of the new seismic coverage. The maximum sediment thickness is re-interpreted to be 8500 m, considerably thicker than previous interpretation.recognised. The first one, a diachronous Middle Devonian unconformity, is the most extensive, and reflects the mobility of the basement during the basin's early history. The second unconformity within the Late Devonian Buckabie Formation reveals that there were two phases of deformation of the basin sediments.The geochemical results reported in this study show that most of the Adavale Basin sediments have very low concentrations of organic carbon and hydrocarbon fractions. Maturity profiles indicate that the best source rocks of the basin are now in the mature stage for hydrocarbon generation. However, at Gilmore and in the Cooladdi Trough, they have reached the dry gas stage. The maturity data provide additional evidence for the marked break in deposition and significant erosion during the Middle Devonian recognised on the seismic records, and extend the limits of this sedimentary break into the northern part of the main depression.Hydrocarbon potential of the Adavale Basin is fair to poor. In the eastern part of the basin, where most of the data are available, the prospects are better for gas than oil. Oil prospectivity may be improved in any exinite-rich areas that exist farther west, where palaeo-temperatures were lower.
THE SUBSURFACE GEOLOGY OF THE WESTERN OFFICER BASIN — RESULTS OF SHELL'S 1980-1984 PETROLEUM EXPLORATION CAMPAIGN
Authors: Townson W.G.
Published: August 2017

The Officer Basin described in this paper includes four Proterozoic to Lower Palaeozoic sub-basins (Gibson, Yowalga, Lennis, Waigen) which extend in a northwest to southeast belt across 200 000 sq. km of central Western Australia. These sub-basins are bounded by Archaean to Proterozoic basement blocks and are almost entirely concealed by a veneer of Permian and Cretaceous sediments. Depth to magnetic basement locally exceeds eight kilometres.Until recently, information on the sub-surface geology was limited to shallow levels, based on the results of a petroleum exploration campaign in the 1960s and the work of State and Federal Geological Surveys. In 1980, the Shell Company of Australia was awarded three permits (46 200 sq. km) covering the Yowalga and Lennis Sub-basins. The results of 4700 km of seismic data and three deep wildcat wells, combined with gravity, aeromagnetic, Landsat, outcrop and corehole information, has led to a better understanding of the regional subsurface geology.The Lennis Sub-basin appears to contain Lower to Middle Proterozoic sediments, whereas the Yowalga Sub- basin is primarily an Upper Proterozoic to Lower Cambrian sequence which comprises a basal clastic section, a middle carbonate and evaporite sequence and an upper clastic section. Widespread Middle Cambrian basalts cap the Upper Proterozoic to Lower Cambrian prospective sequence. Late Proterozoic uplift resulted in salt- assisted gravity tectonics leading to complex structural styles, especially in the basin axis.Despite oil shows, organic matter in the oil and gas generation windows and reservoir-quality sandstones with interbedded shales, no convincing source rocks or hydrocarbon accumulations have yet been located. The area remains, however, one of the least explored basins in Australia.
THE GEOLOGY AND HYDROCARBON POTENTIAL OF THE NORTH-WESTERN OFFICER BASIN
Authors: Phillips Bruce J. , James Alan W. , Philip Graeme M.
Published: August 2017

Recent petroleum exploration in EP 186 and EP 187 in the north-western Officer Basin has greatly increased knowledge of the regional stratigraphy, structure and petroleum prospectivity of the region. This exploration programme has involved the drilling of two deep stratigraphic wells (Dragoon 1 and Hussar 1) and the acquisition of 1438 km of seismic data. Integration of regional gravity and aeromagnetic data with regional seismic and well data reveals that the Gibson Sub-basin primarily contains a Proterozoic evaporitic sequence. In contrast, the Herbert Sub-basin contains a Late Proterozoic to Cambrian clastic and carbonate sequence above the evaporites. This sequence, which was intersected in Hussar 1, is identified as the primary exploration target in the Western Officer Basin. The sequence contains excellent reservoir and seal rocks in association with mature source rocks. Major structuring of the basin has also been caused by compressive movements associated with the Alice Springs Orogeny. The northwestern Officer Basin thus has all of the ingredients for the discovery of commercial hydrocarbons.
FORTESCUE RESERVOIR DEVELOPMENT AND RESERVOIR STUDIES
Authors: Henzell S.T. , Irrgang H.R. , Janssen E.J. , Mitchell R.A.H. , Morrell G.O. , Palmer I.D. , Seage N.W.
Published: August 2017

The Fortescue field in the Gippsland Basin, offshore southeastern Australia is being developed from two platforms (Fortescue A and Cobia A) by Esso Australia Ltd. (operator) and BHP Petroleum.The Fortescue reservoir is a stratigraphic trap at the top of the Latrobe Group of sediments. It overlies the western flank of the Halibut and Cobia fields and is separated from them by a non-net sequence of shales and coals which form a hydraulic barrier between the two systems. Development drilling into the Fortescue reservoir commenced in April 1983 with production coming onstream in May 1983. Fortescue, with booked reserves of 44 stock tank gigalitres (280 million stock tank barrels) of 43° API oil, is the seventh major oil reservoir to be developed in the offshore Gippsland Basin by Esso/BHP.In mid-1984, after drilling a total of 20 exploration and development wells, and after approximately one year of production, a detailed three-dimensional, two-phase reservoir simulation study was performed to examine the recovery efficiency, drainage patterns, pressure performance and production rate potential of the reservoir.The model was validated by history matching an extensive suite of Repeat Formation Test (RFT)* pressure data. The results confirmed the reserves basis, and demonstrated that the ultimate oil recovery from the reservoir is not sensitive to production rate.This result is consistent with studies on other high quality Latrobe Group reservoirs in the Gippsland Basin which contain undersaturated crudes and receive very strong water drive from the Basin-wide aquifer system. With the development of the simulation model during the development phase, it has been possible to more accurately define the optimal well pattern for the remainder of the development.* Mark of Schlumberger
PETROLEUM GEOLOGY OF THE MERLINLEIGH SUB-BASIN, WESTERN AUSTRALIA
Authors: Percival I.G. , Cooney P.M.
Published: August 2017

Esso's recent drilling program in the Merlinleigh Sub-basin, onshore Carnarvon Basin, represents the culmination of the first phase of concerted exploration activity in the area since the WAPET era of the 1960s. The region is unusual among Australian petroleum provinces in having excellent exposures of reservoir, source and seal rocks of Palaeozoic age. While both Esso wells (Burna 1 and Gascoyne 1) failed to encounter hydrocarbons in the primary Wooramel Group play, encouraging potential still exists. The reservoir in the Wooramel Group play is the Early Permian Moogooloo Sandstone, a fluviodeltaic to nearshore sheet-sand facies with porosities to 23 per cent and permeabilities in excess of 100 millidarcys. Likely hydrocarbon sources are siltstones in the overlying Byro Group, with total organic carbon contents averaging 3 per cent, and calcilutites in the subjacent Callytharra Formation with similar organic content. Locally, the Jimba Jimba Calcarenite Member (Billidee Formation) and the Cordalia Sandstone also provide rich source units. The least certain aspects of the Early Permian play are fault and top seal, and reservoir quality at depth. Notwithstanding the relatively shallow depths to source strata in the area, vitrinite reflectance analyses from drill cores indicate that maturation is attained as shallow as 900 m on the folded and faulted western margin of the sub-basin, and at an approximate depth of 1200 m in the depocentre beneath the Kennedy Range. This can be related to high regional heat flow, and to erosion of some 1500-2000 m of sediments prior to the regional Early Cretaceous transgression.Older plays which have been identified in the area remain to be adequately evaluated. Potential reservoir sands are present in the Silurian Tumblagooda Sandstone, the Middle and Late Devonian Nannyarra and Munabia Sandstones, and the Early Carboniferous Williambury Formation. Possible source rocks include carbonates of Middle Devonian and Early Carboniferous age. One of the objects of current research has been to locate areas where seal, provided by the glacigene Lyons Formation of Late Carboniferous-Early Permian age, is sufficiently thin to permit economic drilling.
THE POINT TORMENT SEISMIC SURVEY: A SEMI-PORTABLE SEISMIC OPERATION
Authors: Angove Ron
Published: August 2017

Point Torment, an area of low-lying tidal mudflats and adjacent coastal peninsula, was the site of a seismic survey unique to Australian geophysical exploration. This survey was conducted by Esso Australia Ltd and the area, part of EP 104, is located north of the township of Derby in Western Australia.Surface conditions in the area varied from thickly wooded grassland on the peninsula to open mudflats. Vehicle access to the mudflats was severely restricted and helicopter support was necessary to maintain the seismic operation throughout. The operation was extremely labour intensive; for example, line-cutting through mangrove areas was carried out by hand.Seismic recording was achieved using an OPSEIS* 5500 digital radio telemetry system. With this system data is collected by portable field units labelled Remote Telemetry Units (RTU's) and subsequently retrieved by Radio telemetry and permanently stored on magnetic tape by a Central Recording Station (CRS). This was the first instance of this system being employed in Australia.
NEW PRESSURE ANALYSIS TECHNIQUE USING REPEAT FORMATION TESTER DATA
Authors: Samson Paul N. , Fligelman Haim , Braester Carol
Published: August 2017

Current practice is to derive permeability from the pretest of wireline formation testers by the conventional Horner plot method. The major drawback of this type of analysis is the reliability of the flow time and flow rate estimates.A new technique to derive permeability from pressure response during the sampling period has been developed. The new method is based on the principle that at the end of the sampling period the volume of the fluid in the chamber is equal to the nominal volume of the sample chamber.The suggested method applies the approximation of the continuous pressure decline by a series of pressure steps as applied for water influx calculations.In its present form the technique has limitations due to flow regime shapes, number of phases present and the degree of formation damage.Research is underway to find acceptable solutions for the stated limitations.
PARAGLACIAL AEOLIANITES: POTENTIAL NEW HYDROCARBON RESERVOIRS, GIDGEALPA GROUP, SOUTHERN COOPER BASIN
Authors: Williams B.P.J. , Wild E.K. , Suttill R.J.
Published: August 2017

Facies analysis of core from the Gidgealpa Group has led to the first recognition of sandstones of aeolian origin in the Cooper Basin. The aeolian suite was recognised in core from the Merrimelia Formation penetrated by wells within the Merrimelia field.The Merrimelia 5 aeolianites occur in core between 8603 and 8659 ft drill depth. These were correlated to similar facies in core from Merrimelia 1 between 9649 and 9674 ft drill depth, where other lithotypes of the suite were identified.Gamma ray-sonic log response over cored aeolianite intervals can be correlated to Merrimelia 13, where similar aeolian sediments are interpreted for an uncored interval of Merrimelia Formation.The overall glacigenic nature of the Merrimelia Formation is well documented but this discovery records the first aeolian suite in the Gidgealpa Group and may also document the first subsurface example of cold-climate aeolianites.The aeolianites are porous, poorly cemented, coarse and fine grained sandstones dominated by parallel lamination. Sharp, planar truncation surfaces divide the suite into units composed mainly of translatent wind ripple lamination with minor amounts of sandflow bedding. Primary depositional dip (post-compaction) varies between 0° and 25° suggesting preservation of dune lee-slope strata. Local deformation of avalanche foresets is also visible in the core.The gamma ray-sonic logs of the thick (1190 ft (363 m)) Merrimelia Formation in Merrimelia 5 indicate thick (760 ft (232 m)) porous sandstones. These originate from distal aeolian and distal sandy braidplain environments. In core from Merrimelia 1, aeolianites are interbedded with proximal outwash fan conglomerates. Also gamma ray-sonic logs of the interval indicate thinning of the aeolianite sands. These two observations indicate a nearby depositional edge to the aeolianites.A low interval transit time on sonic logs is characteristic of the porous aeolianite sand. This response produces an identifiable change in seismic reflections where the sands are developed, which allows mapping of the sand distribution from seismic data.A 6 to 8-km wide band of aeolianite sand facies trending southeast — northwest has been mapped. This porous aeolianite sand facies is interpreted to pass laterally into outwash fan, braidplain and interdune deposits.Potential hydrocarbon traps may occur at the top of the aeolianites, or within them beneath intraformational seals formed by muddy interdune facies. The recognition of an aeolian suite at Merrimelia indicates the potential for similar facies development elsewhere in the southern Cooper Basin. Locally these could form important reservoirs beneath the level of existing production.
PALM VALLEY — A CASE FOR INTERPRETATION, 1965-1984
Authors: Sabet M. , Franks L.
Published: August 2017

During the past 18 years, estimations of reserves of the Palm Valley gas field were the subject of many unpublished studies and one that was published in the Journal of Petroleum Technology by Strobel, Gulati and Ramey in 1976. The unpublished studies relied on standard methods of volumetric and material balance calculations. Because the Palm Valley reservoir is naturally fractured, static reservoir pressure estimates made from pressure buildup tests are erroneous unless a well is closed to a Horner time ratio of 1.5 or less. This was not done at Palm Valley and consequently all material balance estimates of gas-in-place were uneconomically low.The estimates of Stobel et al. (1976) were based on matching interference test data observed in two wells during a constant flow period of 18.75 days, which was followed by a pulse test. However, their model matched the pressure observed at one well and failed to match the pressure observed at the second, more distant well. Their reserve estimates were also very low.In this study, a reservoir simulator was used to formulate a model that matched the observed pressures in both wells. Except for the reservoir area, all of the reservoir parameters derived by Strobel from the interference test data were used. The results show that the Palm Valley reservoir contains between 262 and 356 billion standard cubic feet of gas-in-place in the fracture system and the higher permeability matrix rock. Based on our model and including gas in the tight matrix, it is quite possible that the total gas-in-place ranges between 726 billion standard cubic feet and 1.106 trillion standard cubic feet.
TRENDS IN DATA ANALYSIS FOR PETROLEUM EXPLORATION AND DEVELOPMENT
Authors: Lindseth R.O.
Published: August 2017

The computer world is presently locked in a race to produce the futuristic fifth generation computer, one which will simulate some parts of human intelligence. At the back of this is the current interest in expert systems and their adaptation to petroleum exploration and development. Converging hardware and software technologies, combined with industry requirements, show a definite trend to move from the emphasis on hardware and operations systems toward software and informational systems. It is not possible to predict the precise form in which this will impact petroleum industry operations but it is certain that much greater analytical power and control will rest in the hands of the interpreters enabling much higher rates of productivity and effectiveness in the location of hydrocarbon reservoirs.
QUEENSLAND PETROLEUM ACT — RUSTING ANACHRONISM OR WELL-OILED DISCRETION?
Authors: Gately D.J.
Published: August 2017

Petroleum legislation in Queensland has been in place for some 70 years. Today's explorer finds that many of his rights derive from concepts and practices formulated well before the advent of the complicated farmout and joint venture arrangements that increasingly form the framework of exploration activities.The primary tenement for exploration is the Authority to Prospect. However, the legislation is largely silent with respect to Authorities to Prospect, leaving the great bulk of issues arising out of that form of tenement to be determined by the Minster in his absolute and unfettered discretion; while the need for workable administrative practices will entail some uniformity, certainty as to the rights arising out of any Authority to Prospect can only be gained by reverting to the actual authority document.The explorer expects that his exploration rights (i) will not be unduly hampered by competing rights of land owners; (ii) will be capable of being dealt with and assigned in accordance with current industry practices; and (iii) will in the event of success lead to the grant to him of a production title. Those expectations are not entirely satisfied, and the paper recommends certain reforms, including:an express legislative statement that the holder of an Authority to Prospect has exclusive rights to explore in respect of the area the subject of his authority;that the holder of an Authority to Prospect satisfy the obligation to make compensation prior to entry by the lodging of a security bond;that compensation be determined at first instance in the Land Court;that the statutory right to the grant of a Petroleum Lease to the holder of an Authority to Prospect be restored.
DEREGULATION OF THE AUSTRALIAN OIL MARKET
Authors: Hart GE.
Published: August 2017

The marketing of domestic crude oil has been regulated by the Federal Government since production began in the early 1960's. In late 1984 the Government decided, after an extensive review, to partially deregulate immediately and to move to a substantially deregulated domestic oil market by 1988.After only four months of the new arrangements the Government announced a further review claiming that changes in international and domestic market conditions had led to calls from the industry to accelerate the move to deregulation. The Government would also have been influenced by the public perception that rising petrol prices were a result of government policies.Deregulation would directly affect the prices and consumption patterns for domestic crude oils. Indirect effects would include changes to domestic oil exploration activity, the competitiveness of product imports, regional product prices, the viability of some Australian refineries and coastal shipping activity.The diverse positions taken during the mid 1985 review reflected differing assessments of the consequences of deregulation and differing impacts on interested parties. Large fuel users such as primary producers and motorists favoured deregulation in the hope of lower prices. Oil producers were split, with the small producers generally opposing deregulation and the two large producers favouring it under most conditions. Refiners too were split, with the majority favouring deregulation. Refinery and shipping unions were opposed for fear of job losses.The Government decided to halt the move toward deregulation but to review the position again in 1987. In preparation for that review the industry should work hard at improving and communicating its understanding of the complex implications of this vital issue.
THE ECONOMICS OF MARGINAL OFFSHORE OILFIELDS IN AUSTRALIA
Authors: Heron D.H. , Jacobs F.A.
Published: August 2017

Australia's self sufficiency in oil will drop to below 50 per cent by the middle of the next decade unless major discoveries are made within the next few years. There is still a confusing series of permit regimes and fiscal frameworks applicable to exploration and development operations, and no indication of any upturn in offshore activity. If the decline in self sufficiency is to be halted, Industry needs to be assured that it will be allowed to operate under a simple unchanging set of rules such that it is guaranteed a fair return on its risk capital investment.There are many marginal oil discoveries which remain undeveloped for a variety of reasons, but the economics of their development must obviously be the one major limiting factor. A recoverable reserve of 15 million barrels of oil with peak production of about 8000 barrels of oil per day will in most instances provide a base development level with rate of return of 15 + per cent after tax. The new resource rent tax will have only a marginal impact on a development of this size, but the increasing impact of the resource rent tax as reserves and productivity increase above the base level will limit the rate of return on many marginal offshore discoveries to about 21 per cent.It is in marginal discoveries that there is a significant downside risk in development, and producers need to be assured of a reasonable risk loaded rate of return before committing to development. There are many ways of protecting operating companies from the relatively high risks of entering into a marginal offshore development. We have looked at only one of these and suggest that government might consider a lowering of the resource rent tax to 20 per cent for projects with reserves of less than 25 million barrels.
A GEOCHEMICAL INVESTIGATION OF OILS AND SOURCE ROCKS FROM THE SURAT BASIN
Authors: Philp R. P. , Gilbert T. D.
Published: August 2017

A series of twelve oils and five source rocks and potential source rocks from the Surat Basin have been subjected to detailed geochemical analyses. Particular attention has been given to determining the distribution of various classes of biomarkers such as the steranes and triterpanes. The results from this study have shown that the Cabawin oil is derived from the Permian Back Creek Formation and has a high content of marine organic source material. The Triassic/Jurassic oils have a different source from the Cabawin oil and are dominated by land plant source material. Within the Triassic/Jurassic oils there are subtle variations in biomarker distributions suggesting that some oils may have small but additional amounts of different source materials. A number of Cretaceous and Jurassic potential source rocks (i.e. Walloon) have biomarker parameters clearly indicating levels of maturity at which oil generation is impossible.A number of the oils in this basin are extensively biodegraded. In particular biodegradation has been very heavy in the Riverslea/Yapunyah area. With the exception of Conloi oil, all the oils appear to have been exposed to similar levels of maturity. A biomarker migration parameter has provided some tentative evidence to suggest that, in general, oils in the southern part of the basin have migrated further than those in the northern part.In summary, the biomarker data from oils and source rocks of the Surat Basin have been used to provide a new insight into the origin of the Surat Basin oils and their post-formation history.
POROSITY AND PERMEABILITY OF RESERVOIRS AND CAPROCKS IN THE EROMANGA BASIN, SOUTH AUSTRALIA
Authors: Gravestock D.I. , Alexander E.M.
Published: August 2017

When effective porosity and permeability are measured at simulated overburden pressure, and grain size variation is taken into account, two distinct relationships are evident for Eromanga Basin reservoirs. Reservoirs in the Hutton Sandstone and Namur Sandstone Member behave such that significant porosity reduction can be sustained with retention of high permeability, whereas permeability of reservoirs in the Birkhead Formation and Murta Member is critically dependent on slight porosity variations. Logging tool responses are compared with core-derived data to show in particular the effects of grain size and clay content on the gamma ray, sonic, and density tools, where clay content is assessed from cation exchange capacity measurements. Sonic and density crossplots, constructed to provide comparison with a water-saturated 'reference' reservoir, are advantageous in comparing measured effective porosity from core plugs at overburden pressure with porosity calculated from logs. Gamma ray and sonic log responses of the Murta Member in the Murteree Horst area are clearly distinct from those of all other reservoirs, perhaps partly due to differences in mineralogy and shallower depth of burial compared with other formations.
EXPERIENCE WITH THUMPER, DYNAMITE, AND VIBROSEIS SOURCES IN EP 308, THE EASTERN CANNING BASIN
Authors: Stienstra J.J. , Prudence T.J.C. , Haneveld C.J.
Published: August 2017

The aim of Shell's seismic survey was to acquire high resolution data in the shallow part of the section (0.3-1.0 seconds) as an aid to prospect definition. Extensive testing was carried out with Thumper, dynamite, and Vibroseis sources to determine which source would best meet this data requirement. Source and group intervals were set at 24 m.At the experimental stage Seismograph Services Ltd were engaged to provide dynamite and Vibroseis capabilities, and Petty-Ray Geophysical to provide a Thumper source. The Royal Dutch/Shell research laboratory in The Netherlands also provided two sets of downhole geophones to assist with analysis of near surface signal character. Test data, excepting the downhole geophone traces, were processed in the field by Seismograph Services Ltd.Field processing results indicated that the Vibroseis was the best source, although special attention was needed to ensure adequate low frequency energy was input in poor data areas. In-house processing of production and downhole Vibroseis data suggests that low frequency attenuation may still be an area for future concern. Ministack and downhole geophone data suggest that Vibroseis data quality is enhanced at lower drive levels, set at 20 per cent (Seismograph Services Ltd relative scale) for this survey. The results of testing in EP 308 have provided Shell with useful experience for future data acquisition planning in this part of the Canning Basin.
RESERVOIR SIMULATION FOR RESERVOIR MANAGEMENT
Authors: Kaliszewski A.B.
Published: August 2017

The Hutton reservoir in the Merrimelia Field (Cooper-Eromanga Basin) was the subject of a 3-D reservoir simulation study. The primary objective of the study was to develop a reservoir management tool for evaluating the performance of the field under various depletion options.The study confirmed that the ultimate oil recovery from this strong water drive reservoir was not adversely affected by increasing total fluid offtake rate. However, any decisions regarding changes to the depletion scheme such as increasing production rates, if based solely on computer simulation results, should be viewed with caution. Careful monitoring of any changes to the depletion philosophy and checking of actual data against simulation predictions are essential to ensure that oil production rate and ultimate recovery are optimised.The model assisted in evaluating the economics of development drilling. While the simulation results are dependent on the validity of geological mapping, the model was useful in confirming that, due to very high transmissibility in the Hutton reservoir, additional wells would only accelerate production rather than increase ultimate recovery. The issue of drilling wells thus became one of balancing the benefits of accelerating production against the geological risk associated with that well.Interaction between the reservoir engineer and various disciplines, particularly development geology, is critical in the development and application of a good working simulation model. This was found to be especially important during the history matching phase in the study. If engineers and development geologists can learn more of the others' discipline and appreciate the role that each has to play in simulation studies, the validity of such models can only be improved.The paper addresses a number of the pitfalls commonly encountered in application of reservoir simulation results.
THE DEVELOPMENT AND EARLY PERFORMANCE OF THE NORTH RANKIN FIELD
Authors: Posaner F.M. , Goldthorpe W.H.
Published: August 2017

The North Rankin gas field is the first field to be developed as part of the North West Shelf Project and has now been on stream for some two years. With a most likely gas-initially-in-place of 11TCF (308 × 109 m3), it is the largest appraised gas-condensate field in Australia.At the current stage, gas is being produced from one platform (the North Rankin 'A' platform) entirely for domestic consumption. Future development involves the drilling of additional wells to provide gas for export as liquefied natural gas (LNG) to Japan, installation of a second platform, and construction of an additional onshore plant to manufacture the LNG. In addition, a gas recycling project is to be implemented on the North Rankin 'A' platform to increase the recovery of condensate by utilizing spare platform processing capacity available prior to reaching plateau LNG exports.The present paper reviews the development and performance of this major field over the first two years of its producing life. Emphasis is placed on the reservoir pressure performance, particularly in relation to the reservoir geology.
DRILLING MUD EVALUATION OF SOUTHWEST QUEENSLAND WELLS
Authors: Lake B. , Muecke N.
Published: August 2017

One of the primary functions of a drilling fluid is to provide suitable conditions for the safe and effective evaluation of the wellbore. Current drilling fluid evaluation techniques rarely include the costs of poor or inconclusive well evaluation or other mud related costs such as rig time lost due to hole problems and additional cement required for washed out hole.In a study of 17 exploration and appraisal wells drilled in southwest Queensland, inclusion of all measurable mud related costs radically changed previously held beliefs on mud system cost effectiveness. The study showed a cost advantage of approximately 30 per cent when using KCI-polymer over wells drilled with gellignosulphonate. Mud product consumption cost was shown to be only part of what must be considered when evaluating the overall cost effectiveness of a drilling fluid. Evaluation of a mud system was shown to require a detailed analysis of all drilling and evaluation problems encountered during the course of drilling a well.
PETROLEUM EXPLORATION AND DEVELOPMENTS IN QUEENSLAND DURING 1985
Authors: Randal M.A.
Published: August 2017

Petroleum exploration in Queensland during 1985 remained at the high levels that existed during 1984. Of the 115 wells spudded, 88 were wildcat exploration wells, 24 were appraisal wells, and three were development wells. New field discoveries numbered 23, being 16 oil and 7 of gas, the highest number ever recorded. All but two of the appraisal wells and all three development wells were successful. Seismic surveys totalled 23 158 km of subsurface section, 75 per cent in the western part of the state in the Eromanga/Cooper and Eromanga/Galilee basins and their environs, and the remainder in the Surat and Bowen basins. Similar levels of exploration are expected during 1986, although the amount of seismic surveying may decrease as much as 20 per cent. Exploration is expected to be in mostly the same basins as now over the next 15 years.Two liquefied petroleum gas (LPG) separating plants came on stream in 1985 in the Surat/Bowen Basin, one at Kincora and one near Wallumbilla, with a combined output capacity of 50 000 tonnes annually. At Eromanga a mini-refinery with a capacity of about 880 barrels of oil per day commenced operations producing mostly distillate. Petroleum Leases were granted during the year over the Tintaburra and Bodalla South oilfields near Eromanga, and over the Riverslea and Yapunyah oilfields in the Surat region.Queensland's petroleum reserves now stand at 66 million barrels remaining recoverable oil, 17 billion cu m gas, and 500 000 tonnes of LPG. Daily production is about 29 000 barrels of oil and condensate, about 1.2 million cu m of gas, and 97 tonnes of LPG.There is relatively little impact to petroleum exploration in Queenland through the setting aside of land for special purposes. Legislation and administrative arrangements allow exploration in National Parks and Forest Reserves under conditions set down by the controlling bodies.
LEGAL AND TAXATION ASPECTS OF FARM-INS AND FARM-OUTS OVER EXPLORATION TENEMENTS
Authors: Allen M. Williamson J.
Published: August 2017

The paper considers the basic capital gains tax implication arising out of farm-outs and how to structure those farm-outs in the light of up-front payments and disproportionate funding. In particular, consideration is given to the acquisition and disposal dates and how altering those dates will impact on the asset cost base of the farmor/farmee. The problem of determining value is also considered.
THE CORPORATION AND THE FAMILY IN THE RESOURCES INDUSTRY — CORPORATE RESPONSIBILITY TOWARDS THE 21ST CENTURY
Authors: Crowe D.S.
Published: August 2017

The changing sociological scene places greater emphasis today on self-fulfilment psychology and individual expectations, often at the expense of responsibility in relationships. This, coupled with greater demands on staff (especially on managers of corporations) places, at times, unrealistic demands on normally stable relationships, particularly in a marriage. The result is increased family tension, often resulting in marriage breakdown with significant scarring of partners and children; those individuals, so affected, suffer reduced productivity in their work roles.As we approach the 21st century, there is emphasis, in the management of corporations, on innovation and cost efficiency, thus placing greater pressure on individual staff.This paper takes the position that corporations, in their own self-interest and in the interest of staff, need to assess the impact of their current policies on not only their staff but also on staff families. While maintaining that it remains the single responsibility of individuals to make decisions on managing, effectively, their corporate/private lives, the author supports the proposal of others (Evans and Bartolome, 1980) that corporations' policies should help, not hinder, the process.Corporations which continue to ignore these considerations will incur long term consequences with significant impact on productivity and efficient management, aside from possible disastrous impact on their staff and families.Corporations in Australia are taking steps to address this situation but much more needs to be done. This was highlighted in the March 1985 'Middle Management' course with its associated Spouses Programme presented jointly by Australian Mineral Foundation and The Australian Administrative Staff College.Effective communication is at the heart of the matter, but no amount of training on this subject will bear fruit unless there is an associated commitment by executives to improve the effectiveness of their communication process, both in their corporate and family roles.
CONTRIBUTING TO APEA'S RESPONSE ON ENVIRONMENTAL ISSUES — THE NEED FOR SHARING MEMBER COMPANIES' EXPERIENCE AND EXPERTISE
Authors: Stone M.J.
Published: August 2017

In early 1986 the APEA Environmental Affairs Committee developed an environmental policy to provide a framework for the Association's response on environmental issues which affect the petroleum industry. To fulfil the aims of this document there is a need for member companies to assist the committee in addressing and promoting the industry's environmental management aims. Environment is defined in broad terms in current legislation. To embrace this definition, APEA must adopt a position that reflects the industry's desire to be represented at the policy review stages of such environmental issues as land use proposals. Since 1971 only eight papers in the APEA Journal have addressed environmental issues. Companies have generally not shared or promoted their individual responses to such issues, although there would be value to the industry as a whole through identifying and discussing environmental management expertise and experience within APEA. Two examples of environmental management practice applied by CSR in Delhi Petroleum's activities in South Australia and Queensland are discussed: a demonstration seismic line within the Witjira National Park, South Australia and the use of rollers for seismic line preparation. Similar examples can probably be identified for all member companies. In generating a pool of operational examples, APEA might better represent the industry's ability and record in this field to governments and to the general public.
A NEW PLAY IN THE GIPPSLAND BASIN
Authors: Lowry David C.
Published: August 2017

Explorers of the Cippsland Basin have generally assumed that the prospective Latrobe Group (Late Cretaceous to Eocene) is separated from the Strzelecki Group (Early Cretaceous) by an angular unconformity dated at about 100 million years before present (Ma). Thus all sub-unconformity traps seen on seismic sections have been assumed to be developed in the unprospective Strzelecki Group. Evidence from seismic sections and wells indicates that this unconformity should be dated at about 80 Ma. The beds deposited between 80 and 100 Ma are part of the Late Cretaceous Latrobe Group and have the potential for both reservoirs and intraformational seals.This new sub-unconformity play can be pursued in areas transitional between the Central Deep and the flanking platforms. On the platforms the prospective beds are absent because of truncation while in the Central Deep they are beyond the reach of the drill.