bluuebunny/crossref_metadata_2025 huggingface dataset:
MURILLA CREEK — AN UNTESTED STRATIGRAPHIC PLAY IN THE SURAT BASIN
Authors: Rigby S.M. , Kantsler A J.
Published: August 2017

In 1978 Shell farmed into Western Mining Corporation's (WMC) permit ATP-241P in the central Surat Basin. A major objective of the venture was to explore for Lower Jurassic stratigraphic traps in the Murilla Creek area on the western flank of the Mimosa Syncline.The Murilla Creek stratigraphic play comprises a series of sand-filled valleys incised into the base Jurassic unconformity surface, forming a dendritic drainage pattern which supplied sediment to the braided stream deposits of the Lower Precipice Sandstone to the east. At their western depositional limit these potential reservoirs are likely to be sealed vertically by a regionally extensive lacustrine shale, and laterally by siltstones and shales within the sub-cropping Middle Triassic Moolayember Formation. Oil charge may either be directly from underlying Triassic source rocks or indirectly from the Permian Blackwater and Back Creek Groups. Exploration of the Murilla Creek area involved the acquisition of 776 km of experimental, reconnaissance and infill seismic and one well (Coalbah 1) which enabled seismic calibration and delineation of the Lower Precipice Sandstone to its seismically resolvable limits.Seismic interpretation confirmed the potential for several stratigraphic traps in the Murilla Creek area. However trap geometries and seal constraints suggest that any stratigraphically trapped oil accumulation would be small (less than 3 MMBBL). Coupled with the considerable geological risks associated with the stratigraphic play, the low potential rewards rendered the play economically unattractive to Shell and WMC and the acreage was subsequently relinquished. However the Murilla Creek stratigraphic play remains untested and, in view of the potential for numerous small oil accumulations, may prove to be an attractive exploration target under more favourable economic circumstances.
APPLICATION OF THE BLACK OIL PVT REPRESENTATION TO SIMULATION OF GAS CONDENSATE RESERVOIR PERFORMANCE
Authors: Goldthorpe W.H. , Drohm J.K.
Published: August 2017

Special attention must be paid to the generation of PVT parameters when applying conventional black oil reservoir simulators to the modelling of volatile oil and gas-condensate reservoirs. In such reservoirs phase behaviour is an important phenomenon and common approaches to approximating this, via the black oil PVT representation, introduce errors that may result in prediction of incorrect recoveries of surface gas and condensate. Further, determination of production tubing pressure drops for use in such simulators is also prone to errors. These affect the estimation of well potentials and reservoir abandonment pressures.Calculation of black oil PVT parameters by the method of Coats (1985) is shown to be preferred over conventional approaches, although the PVT parameters themselves lose direct physical meaning. It is essential that a properly tuned equation of state be available for use in conjunction with experimental data.Production forecasting based on simulation output requires further processing in order to translate the black oil surface phase fluxes into products such as sales gas, LPG and condensate. For gas-condensate reservoirs, such post-processing of results from the simulation of depletion or cycling above the dew point is valid. In principle it is invalid for cycling below the dew point but in practice it can still provide useful information.
PLUNGER LIFT APPLICATION IN DEEP OIL WELLS
Authors: Barry Tim
Published: August 2017

The Patchawarra Central Oilfields 40 km to the north of Moomba are operated by Santos Ltd. Wells produce 52 API oil with a high gas/oil ratio from depths of about 2 956 m (9 700'). A number of wells, not influenced by pressure maintenance, require some form of vertical lift assistance in order to deplete the reservoir effectively.Following a successful trial on a gas well, plunger lift was installed on the Moorari 6 oil well in early 1987 to assess the suitability of this artificial lift method. This installation was the first use of plunger lift in Australia to assist production in a well at this depth.Plunger lift uses a free piston as an interface to prevent fallback of liquids. The plunger is propelled by pressure build-up in the annulus. Crucial to the operation of plunger lift is the gas/liquid ratio. Sufficient gas must be available to produce the liquid load. In suitable wells, no external energy source is required and it provides a very economical method of maintaining production.The Moorari 6 installation was tested at 11.5 m3/d (72 BOPD) on a well previously producing approximately 7 m3/d (44 BOPD) and requiring significant operator involvement for frequent blowdown of the well to atmosphere.As the reservoir depletes, the expected rise in producing GOR will serve to increase the efficiency of plunger lift operation. Currently under consideration is the introduction of extra gas to the casing, which will give a significant production increase in the early life of the installation.
NORTH RANKIN 'A' GAS RECYCLING PROJECT — DESIGN, CONSTRUCTION AND COMMISSIONING
Authors: Holt D.J. , Jong C. de , Rowell D.G.
Published: August 2017

Gas recycling, to increase early production and total recovery of hydrocarbon condensate, was implemented on the North Rankin 'A' platform to take advantage of excess production capacity prior to the commencement of the LNG export phase. By recycling excess 'dry' gas back into the reservoir, condensate production has been doubled, to around 3 000 kl per day (19 000 barrels) per day and ultimate recovery increased.The additional facilities installed included five injection wells, an additional production well, and a 23 MW gas turbine driven gas recompression facility that was retrofitted within existing facilities on the platform. Designed in-house, the facility involved relocation of some operating plant and piecemeal installation of a new 400 tonne module containing a 23 MW aero-derivative gas turbine driven high pressure (30 MPa) centrifugal compressor and ancillary equipment. The compressor set was extensively tested under full load conditions at the manufacturer's works in France before delivery.Offshore construction was complicated by the congested working area and the difficulties of working in and integrating with live production facilities but was completed without major incidents or causing undue interference to platform production. Commissioning proceeded quite smoothly. Full operation was achieved within ten days of initial start-up, and the facility has continued to yield impressive production results.
NEW LIGHT ON THE ORIGIN OF COOPER BASIN OIL
Authors: G.H.Taylor G.H.Taylor , Liu Susie Y. , Smyth Michelle
Published: August 2017

The Cooper Basin in central Australia is a major producer of gas and oil. It is generally accepted that the organic matter in the Permian terrestrial sediments of the Basin was the source of the oil and gas. However, both the coals and the dispersed organic matter (DOM) are rich in inertinite and both inertinite itself and inertinite-rich organic matter have been widely discounted as a possible source for oil.Recent co-ordinated transmission electron microscope and light microscope work on the inertiniterich coals of the Cooper Basin has shown that up to several per cent of some coal samples are composed of microscopic and sub-microscopic alginite. This includes material that had previously been identified with the light microscope alone as degraded sporinite, liptodetrinite or resinite, as well as algal-derived matter, which is too fine to observe with light microscopy. Much of this material of algal origin was selectively degraded at about the time of its deposition, and this degradation appears likely to have had the effect of further enhancing its potential to yield hydrocarbons. Thus, such material should be ranked among the richest potential sources of hydrocarbons when appropriate diagenetic conditions have been attained. Since inertinite and this kind of alginite occur in particularly close association, the presence of inertinite-rich coals and DOM within potential source rocks should be regarded as a highly favourable rather than an unfavourable, indication (as in the past).The quantity of alginite in the very large volumes of inertinite-rich coal in the Basin is more than adequate to account for the oil accumulations. In the Cooper Basin the coals, rather than the DOM, had the better potential for oil generation.
EXPLORATION IN THE NORTHERN BONAPARTE BASIN, TIMOR SEA - WA-199-P
Authors: Whibley Mike , Jacobson Ted
Published: August 2017

Permit WA-199-P, located in the Northern Bonaparte Basin, has undergone an intensive exploration phase from its award on 22 October 1985, which has resulted in the acquisition of 6250 km of 2D seismic and 1558 km of 3D seismic together with the drilling of seven exploration wells. Significant oil shows were recorded in six of these wells.The major play type investigated to date within the permit consists of Jurassic tilted horst and fault blocks. Potential reservoirs comprising medium to coarse grained sandstones of the Jurassic Plover Formation and, to a lesser extent, the Late Jurassic to Early Cretaceous Flamingo Group, are sealed by massive claystones of the Cretaceous Bathurst Island Group. Numerous oil shows have been encountered by drilling within these two reservoirs; however, drilling results from the Avocet-Eider structure indicate that Late Miocene-Recent fault reactivation often breaches the lateral seal of the fault- dependent structures causing leakage of hydrocarbons up the fault.Source extract-oil correlations and maturation studies indicate that the most likely oil sources comprise thermally mature marine claystones of the Flamingo Group and Plover Formation, developed within the Sahul Syncline to the east of WA-199-P. The main period of oil migration was probably Miocene or younger. A number of play types remain untested. These consist of Permian, Intra-Triassic and top Cretaceous fault blocks, as well as fault-independent closures, downdip fault closures and stratigraphic wedge outs of Maastrichtian sand reservoirs, and submarine fan sands developed within the basal Flamingo Group.
THE SOUTHERN BONAPARTE GULF BASIN - NEW PLAYS
Authors: Durrant J.M. , France R.E.
Published: August 2017

Integration of regional exploration data with a new basin model involving progressive basinward salt withdrawal has generated new exploration plays in WA-128-P and WA-211-P, which forms part of the offshore Southern Bonaparte Gulf. This area provides a hydrocarbon habitat that is unique to this part of the Bonaparte Gulf Basin.Three major Palaeozoic megasequences, MS-I, MS-II (A & B) and MS-III, are identified on seismic data and correspond to major stages in the structural and depositional development of the basin, from Silurian through to Triassic times.Early exploration, targeted on structural highs, encountered numerous hydrocarbon shows. Of most recent significance are the Turtle-1 and Turtle-2 wells. Turtle-1 (1984) targeted a midbasin, MS-I high and recovered oil in MS-III. Turtle-2 (1989) tested an additional 510 m-thick, MSII onlap sequence and encountered, within fractured intervals, significant oil and gas influx accompanied by massive lost circulation. Significant live oil was produced on test despite huge damage inflicted to the fracture porosity and permeability during the fourteen-day well control period.Recent geochemical work indicates that the oils recovered from MS-II and MS-III have a common marine source. Oils from MS-III are associated with incompetent seals and meteoric waters and are variably degraded and exhibit low GOR. In contrast, oils of MS-II, associated with competent seals, exhibit high GOR. In consequence, a diversity of new exploratory plays are indicated:Fractured reservoirs in MS-II, stratigraphic onlaps flanking MS-I structures.Stacked turbidites and basin floor fans deposited in the MS-II salt-withdrawal sub-basins.Carbonate banks within the MS-II sub-basin's marginal carbonate complexes.MS-I carbonate structures localised over early salt structures and onlapped by MS-II sediments.Structural and stratigraphic traps of MS-II and III associated with diapiric salt.By virtue of the stratigraphic and structural relationship of MS-II sediments which onlap the flanks of structural highs, these plays have not been previously drilled in optimal locations. Consequently, a new phase of exploration specifically targeted at these plays is now planned to proceed in parallel with exploration of MS-III targets in structural traps. The application of the basin model concepts to these MS-III plays has revealed subtle crestal faulting associated with structural highs. The structural and stratigraphic implications of these observations indicate new plays on the flanks of previously drilled structures.
THE GEOLOGY AND PETROLEUM POTENTIAL OF THE WESTERN ARAFURA SEA
Authors: McLennan Jeanette M. , Rasidi John S. , Holmes Richard L. , Smith Greg C.
Published: August 2017

The northern Bonaparte Basin and the Arafura-Money Shoal Basins lie along Australia's offshore northern margin and offer significantly different exploration prospects resulting from their differing tectonic and burial histories. The Arafura Basin is dominated by a deep, faulted and folded, NW-SE orientated Palaeozoic graben overlain by the relatively flat-lying Jurassic-Tertiary Money Shoal Basin. The north-eastern Bonaparte Basin is dominated by the deep NE-SW orientated Malita Graben with mainly Jurassic to Recent basin-fill.A variety of potential structural and stratigraphic traps occur in the region especially associated with the grabens. They include tilted or horst fault blocks and large compressional, drape and rollover anticlines. Some inversion and possibly interference anticlines result from late Cenozoic collision between the Australian plate and Timor and the Banda Arc.In the Arafura-Money Shoal Basins, good petroleum source rocks occur in the Cambrian, Carboniferous and Jurassic-Cretaceous sequences although maturation is biassed towards early graben development. Jurassic-Neocomian sandstones have the best reservoir potential, Carboniferous clastics offer moderate prospects, and Palaeozoic carbonates require porosity enhancement.The Malita Graben probably contains good potential Jurassic source rocks which commenced generation in the Late Cretaceous. Deep burial in the graben has decreased porosity of the Jurassic-Neocomian sandstones significantly but potential reservoirs may occur on the shallower flanks.The region is sparsely explored and no commercial discoveries exist. However, oil and gas indications are common in a variety of Palaeozoic and Mesozoic sequences and structural settings. These provide sufficient encouragement for a new round of exploration.
THE LANDER TROUGH—A CENTRAL AUSTRALIAN FRONTIER EXPLORATION AREA
Authors: Pegum D. , Loeliger M.
Published: August 2017

The Lander Trough is an almost unexplored area of 30 000 square kilometres in the central western Northern Territory. It has very similar stratigraphy and structural features to the nearby Amadeus, Ngalia and southern Georgina Basins. They all contain fluvio-deltaic to marine sediments of Late Proterozoic to Carboniferous age and were subjected to deformation during several major periods of folding and overthrusting. They are remnants of one depositional basin which covered much of Northern Australia in the Late Proterozoic and Early Palaeozoic Eras. Producing oil and gas fields occur in the Amadeus Basin and there are many oil and gas occurrences in the southern Georgina and Ngalia Basins. The Lander Trough contains up to 3000 metres of largely marine clastic and carbonate sediments which are expected to include mature source rocks and effective reservoirs and seals. Adequate migration paths and trapping mechanisms are believed to be present. The Lander Trough has the potential for commercial petroleum discoveries.
THE ROLE OF RESERVOIR SIMULATION IN THE DEVELOPMENT OF THE CHALLIS AND CASSINI FIELDS
Authors: Gorman I.G.D.
Published: August 2017

The Challis oil field development was approved in 1987 with marginal reserves (for an isolated offshore project) of 22 MMbbl. The initial development envisaged three subsea production wells connected via a riser to a floating production facility with one water injector also being required to maximise recovery. However, due to additional potential in the vicinity of the field, the production system was designed to accommodate up to 10 production/injection wells.Further appraisal in 1988/1989 doubled the reserves to 43 MMbbl and increased the number of initial production wells to seven from five reservoirs. The appraisal results also confirmed earlier concerns as to the structural complexity of the field. Analytical interpretations of the production tests performed on the wells could not be fully reconciled with the available well log, core and seismic data. Furthermore, the analytical models developed from these interpretations could not fully match the test results.Reservoir simulation was used to resolve, where possible, the discrepancies. Individual reservoir models were calibrated with the production test results and used to quantify the major uncertainties and their potential impact on production performance. The simulation results indicated that water injection may not be required. However, the degree of internal reservoir communication and the extent of the expected aquifer support were identified as the two principal unknowns.Production policy and monitoring procedures were structured to resolve these uncertainties as quickly as possible during the production start-up phase. Comparative forecasts of expected performance were developed for each reservoir with various levels of aquifer support. A surface controlled interference test was designed to investigate the extent of internal reservoir communication in the main reservoir.The success of the interference test and the results of the early well performance have confirmed the simulation predictions. Simulation modelling was successful in quantifying the range of expected pressure response (to production) for each reservoir and was able to quickly confirm the degree of pressure support present in each reservoir.
THE TALBOT OILFIELD, VULCAN SUB-BASIN, TIMOR SEA: A TRIASSIC OIL DISCOVERY
Authors: Bourne J.D. , Faehrmann P.A.
Published: August 2017

Talbot-l, the discovery well for the Talbot Field, was the first well of a four well drilling program operated by SANTOS Limited in permit AC/P12 during 1989 and 1990. AC/PI 2 was gazetted for competitive bidding and awarded in February 1989. Following a seismic program involving acquisition of 2660 km of 2-D and 3360 km of 3-D data together with seismic reprocessing, a significant fault-dependent structural high was defined within the 3-D grid. Interpretation of this structure, subsequently named Talbot, revealed tectonic and stratigraphic similarities to the Challis Oilfield, 40 km to the northeast. Talbot-l was chosen as the first well of the commitment program and spudded in November 1989. The well flowed oil at an un- stabilised rate of 4981 BOPD on 7 December 1989, nine months after the permit was awarded.The Talbot-l discovery and the Talbot-2 appraisal have confirmed a modest size oilfield located on a structural horst. The Triassic oil-bearing section is a layered sequence of texturally and mineralogically immature clastics and carbonates deposited in a nearshore marine environment. Because of pre-unconformity structural dip, faulting within the reservoir sequence, layering, and a small gas cap, the Talbot Oilfield will require detailed geological, geophysical and engineering studies to assess the likely production performance of the field. If a Talbot development can be demonstrated to be economic, a third well may be required. Production could commence 12 months from the decision to develop the field.
FISSION TRACK THERMOCHRONOLOGY: APPLICATION TO CONTINENTAL RIFTING OF SOUTH-EASTERN AUSTRALIA
Authors: Dumitru T. A. , Hill K. C. , Coyle D. A. , Duddy I. R. , Foster D. A. , Gleadow A.J. W. , Green P. F. , Kohn B. P. , Laslett G. M. , O'Sullivan A.J.
Published: August 2017

Over the last five to ten years, apatite fission track analysis has developed into a sophisticated technique for studying the low-temperature thermal history of rocks. It has particular utility in oil exploration because its temperature range of sensitivity, about 20° to 125°C, overlaps the oil generation window. Whereas older fission track thermal history approaches relied solely on the sample fission track age, the new interpretive approaches use sample age, single grain age and track length data. They also emphasise the analysis of systematic variations in data patterns in sequences of samples, such as samples from various depths in a well. Laboratory study of the thermal annealing of fission tracks and compilation of fission track data from geological case studies has greatly improved our understanding of apatite fission track systematics, allowing considerably more detailed interpretations of thermal histories.Application of apatite fission track analysis to the rifted continental margins of south-eastern Australia shows that rifting and separation of Australia from Antarctica and the Lord Howe Rise were accompanied by at least 1.5-3 km of uplift and erosion along the Tasman Sea and Bass Strait coasts. Uplift and erosion were much less 100 km or so inland. This shows that the uplift of the south-eastern Australian margins was caused by the continental rifting process, the same process that initiated major subsidence in the sedimentary basins in Bass Strait. The consistent fission track data patterns around south-eastern Australia suggest a generally similar tectonic setting for the Tasman Sea and Bass Strait parts of the margin. Lister et al. (in press) propose that the Tasman part of the margin is an upper plate type of margin that formed above a west-dipping detachment zone. The fission track data suggest that the Bass Strait part of the margin may also be of upper plate type.
A NEW LOOK AT THE STRUCTURAL TRENDS IN THE ONSHORE OTWAY BASIN, VICTORIA, USING IMAGE PROCESSING OF GEOPHYSICAL DATA
Authors: Pettifer G. , Tabassi A. , Simons B.
Published: August 2017

Although the Otway Basin is oriented west-north-westerly, and previously recognised major structural elements follow a similar trend, other structural trends have been found on recently obtained geophysical data.In 1989, an aeromagnetic and radiometric survey of the onshore Otway Basin was completed for the Victorian Department of Industry and the Bureau of Mineral Resources, Geology and Geophysics. This survey, together with a recent gravity compilation by the Geological Survey of Victoria, enables analysis of magnetic and gravity data trends reflecting basement and intra-basin structure.The trend analysis was carried out using modern image processing techniques including simulation of real-time sun-angles of the magnetic and gravity data, and composite images of the radiometric data, to highlight lineaments. This technology enables integration of magnetic, gravity, radiometric and, potentially, seismic, Landsat, topography and bathymetry data for basin structure analysis.The magnetic, gravity and radiometric trend analysis was compared to an earlier Landsat study (Baker, 1980) and a previous seismic data compilation of the Otway Basin (Megallaa, 1986).The present study has revealed the significance of major early Palaeozoic north-south and east-north-east to easterly trends. The latter trends have not previously been identified or discussed in earlier basin reviews. There appears to be a difference between trends reflected in the radiometric and seismic data and trends apparent in the gravity and magnetic data. This could indicate a change in principal stress directions during the evolution of the basin. The shape of the northern margin of the basin appears to be controlled by major north-easterly structures.
A GEOCHEMICAL METHOD FOR ASSESSMENT OF THE THERMAL HISTORIES OF SEDIMENTS: A TWO-WELL CASE STUDY FROM THE GIPPSLAND BASIN, AUSTRALIA
Authors: Alexander R. , Kralert P.G. , Marzi R. , Kagi R.I. , Evans E J.
Published: August 2017

The ester content in kerogen is depleted as sediment maturation progresses in a process which has been shown to correlate with change in the carbon preference index (CPI) of the associated soluble organic matter. We have carried out accurate laboratory measurements of the kinetics of the reaction which causes ester depletion in sediments, and we show how this information can be used to assess the thermal history of sediments. Two wells were selected, Grunter-1 and Volador-1, to provide samples from the Latrobe Group in the Gippsland Basin. The CPI values were measured to assess the extent of reaction at points down each well, and these values were then used with the kinetic parameters for the ester depletion process to obtain thermal histories which are consistent with the available maturity information.This treatment enabled the heat flow from 50 Ma to the present to be assessed and it suggests that at both locations a constant low heat flow during the Gippsland stable phase was followed by a gradual increase from the beginning of the Miocene to present-day values.
THE YAMMADERRY AND COWLE SMALL OFFSHORE FIELD DEVELOPMENTS
Authors: Aberle G.E. , Markwell D.G.
Published: August 2017

The Yammaderry and Cowle oilfields are located 22 km north-west of Onslow, Western Australia and are two and five km respectively from the Saladin oilfield. With estimated crude oil reserves of 1.6 and 2.3 MMBBLS respectively these developments are considered small.A development strategy was formulated to provide minimum facility structures and to take maximum advantage of the very competitive design and construction capabilities being offered locally. Development costs were minimised by using the existing Saladin processing facilities on nearby Thevenard Island and by sharing mobilisation costs of major construction and development plant items.The offshore monopod structures were designed to withstand cyclonic wind and wave conditions while supporting minimal production equipment and acceptable access structures.The main advantages of these structures are that they can be fabricated in any competent heavy fabrication shop, well removed from the site, and can be transported easily by road and rig tender vessel to the installation site. Installation is generally carried out by the jack-up drilling vessel mobilised to drill the production wells.The offshore pipelines were designed as paired bundles to accommodate multiphase product flow and gaslift supply and to provide greater confidence in achieving on-bottom stability.Since the development strategy embraced two independent paths, these being structure/well development and offshore pipelay, the risk of claims due to late delivery of either structures or line pipe was removed. The success of the project was kept independent of any one major component of plant and throughout all phases of the project, realistic contingency plans and procedures were available.
THE ENVIRONMENT FOR RAISING FUNDS FOR PETROLEUM EXPLORATION IN THE 1990s
Authors: Epper Mark , Charters John
Published: August 2017

Private shareholders' equity has traditionally funded greenfield exploration programs in Australia in the 1980s. In the next decade junior exploration companies will again need to rely on funding from both current and potential shareholders. However, the major difference between the 1980s and the 1990s will be the level of difficulty for companies seeking to raise funds. Recent events have sapped potential investor confidence, particularly private investors, and notably, in oil and gas exploration companies.The recent events in the Middle East and the need for some degree of energy self-sufficiency make investment in oil exploration essential for Australia right now. Exploration requires substantial amounts of risk capital which, at this time, is not flowing from traditional sources. Rather, we are seeing a concentration of ownership in the hands of financial institutions and a handful of producing companies and foreign multinationals. It is essential for the Federal Government to recognise the need to offer further incentives to encourage the private sector to invest in exploration companies. In this paper we suggest that the most effective mechanism for such incentives is through some minor modifications to the Australian taxation system.The oil exploration industry must pursue Government in a co-ordinated manner for assistance in raising funds particularly as the requirement for action is urgent. Industry bodies, such as the Australian Petroleum Exploration Association Ltd (APEA) have recently petitioned the Federal Government with recommendations but the Government has failed to accept these proposals on the grounds that they are inconsistent with present tax policy. If this is the case it is time present policy was changed.Clearly, all exploration companies will take whatever action is possible to raise funds for exploration and not simply look in vain for government salvation by handout. However, in the interests of Australian national security, the government has a responsibility to encourage and foster oil and gas exploration.Since planning for this paper commenced in July 1990, oil prices have leapt from US$18 to approximately US$40 per barrel. Should prices such as these (not experienced since the early 1980s) continue, it will make investment in exploration companies more attractive to all investors while at the same time it will test severely the endurance of the equity market generally.
BUSINESS AND TAX ISSUES FOR PETROLEUM EXPLORATION AND DEVELOPMENT COMPANIES INVESTING IN THE UNITED STATES OF AMERICA
Authors: Hayne Catherine A.
Published: August 2017

Oil and gas exploration and production opportunities in the United States represent possibilities for investment by Australian petroleum companies in the 1990s. This paper focuses on the unique characteristics of the oil and gas industry, and is intended as an entrepreneurial guide to some of the practical business and tax issues which corporate executives will confront when proposing to do business in the United States. It provides a detailed examination of the key issues, but, due to the complexity of United States and Australian laws, this paper should not be used as a substitute for detailed advice.
DEVELOPMENT OPPORTUNITIES IN THE KINGFISH AND WEST KINGFISH FIELDS, GIPPSLAND BASIN
Authors: Mudge W.J. , Curry J.J.
Published: August 2017

A multi-disciplinary field study of the Kingfish and West Kingfish Fields in the Gippsland Basin covering geological, geophysical, reservoir and facility engineering issues has identified potential undiscovered and undeveloped reserves in and around the fields. The study resulted in the initiation of an 11 well infill drilling program on the West Kingfish Field, and identified the need for two outpost wells which, if successful, could lead to the installation of additional platforms. Water handling and compression upgrades in the near and long term were also evaluated to optimise field production performance.The Kingfish and West Kingfish field study has formed a blueprint for similar studies in other major oil fields in the Gippsland Basin in which similar appraisal and/or development opportunities may exist.It is anticipated that outpost and infill drilling programs originating from these studies will play a major role in mitigating production decline and increasing ultimate recovery in the mature oil fields of the Gippsland Basin.
THE DEVELOPMENT GEOLOGY OF THE TUBRIDGI GAS FIELD
Authors: Thompson Mark
Published: August 2017

The Tubridgi Gas Field is located in the south of the Barrow Sub-basin, onshore in the Carnarvon Basin, Western Australia. The accumulation was discovered by Pan Pacific Petroleum NL in June 1981 with the drilling of the Tubridgi-1 well. Subsequent to Tubridgi-1, eight appraisal wells have been drilled, six of which were successful. The latest wells, Tubridgi-7 and-8, drilled in September 1990 by current operator Doral Resources NL, have enabled geological and petrophysical models for the field to be refined. These models were utilised for reserve determinations which were used to negotiate gas supply contracts and secure project financing to ensure the fields successful commercial development. Tubridgi gas is trapped within a broad, low relief, northeast-trending anticlinal closure. Reservoirs for the accumulation are the Middle to Upper Triassic Mungaroo Formation, Upper Cretaceous Flacourt Formation of the Barrow Group and Birdrong Sandstone of the Cretaceous Winning Group. All three units exhibit porosities averaging 29-30 per cent, with permeabilities of 3-16 D in the Mungaroo and Flacourt Formations and 157 mD in the Birdrong Sandstone. Vertical seal for the accumulation is the Muderong Shale of the Winning Group.The Tubridgi Gas Field is the first onshore Carnarvon Basin hydrocarbon accumulation to be commercially developed. Gas production into the Dampier-to-Bunbury Natural Gas Pipeline commenced on 26 September 1991 and within one month had reached contract volumes averaging 22 MMCFD (623 000 m3/d). Field life is anticipated to be ten years.
HARRIET GAS GATHERING PROJECT, BARROW SUB-BASIN
Authors: Williams Adrian , Macey Dave
Published: August 2017

Since start-up of Harriet oil production in early 1986, the TL/1 joint venturers have attempted to find a use for the oil-associated gas as well as other gas from neighbouring small gas fields. Initially, supplies from the North West Shelf Project were well in excess of local demand and acted as a damper on new development projects. With time, however, gas reserves in the Harriet area were augmented through new discoveries and the State's demand grew steadily until, in mid 1990, a new project could be justified. In December 1990, an agreement was reached with the State Energy Commission of Western Australia (SECWA) for the supply of 140 PJ (123 BCF) of gas over a ten year period, with an option for a further 65 PJ (57 BCF). First gas supplies are planned for June 1992.The project is based on the supply of Harriet solution gas as well as free gas from the Campbell, Sinbad and Rosette fields. Bambra is a potential future addition but is not required initially for the contract.The project involves small offshore platforms at Campbell and Sinbad, a wet gas pipeline from these platforms to Varanus Island, a facility on the Island to dry the gas and boost the pressure, and a transmission line to SECWA's system, approximately 100 km distant.The transmission pipeline has considerable reserve capacity over the initial contract flowrate of 30 to 60 TJ/day (26 to 52 MMCFGD) and provides a basis for further small gas projects utilising either flare gas from new oil developments or new gas field developments.
TECTONIC CONTROL OF WORLD OIL RESERVES: AUSTRALIA'S POSITION
Authors: Davidson John K.
Published: August 2017

Although simple extensional clay models may be representative of grabens tens of kilometres in length, rotational divergence of continents on a sphere produces very different structures. Repeated periods of compression during separation result in wrench faults and compressional anticlines developing along major crustal fractures as a consequence of changes in momentum between a continent and adjacent smaller continental blocks along its rifted margin.The global distribution of rotationally divergent continental margins can be accounted for by asymmetric expansion of the earth. The southern bulge caused by expansion has emphasised non-marine deposition on southern continents with marine deposition more common in the northern hemisphere.Phanerozoic source rocks of the northern hemisphere account for 97 per cent of the world's produced and current reserves of oil. Australia's share of this extreme distribution asymmetry is less than one half of one per cent, yet the country covers five per cent of the Earth's continental crust.The proportion of undiscovered oil reserves outside OPEC and the former USSR is approximately 30 per cent, or some 12 per cent of the world's estimated ultimately recoverable reserve of 2 trillion (Tera) barrels. The majority of Australia's undiscovered reserves lie on the North West Shelf where about 12 per cent of the country's estimated ultimately recoverable reserve could be found.Although Australia is politically stable, lower petroleum taxes would attract exploration for smaller, structurally complex oil fields. While such taxes may be considered politically difficult at present, a by-product of concerted oil exploration would be an enormous increase in Australia's gas reserves to feed the national pipeline grid for the 21st century. Industry can assist increased success rates by greater attention to current technical deficiencies, such as the structural interpretation of seismic lines.
THE TECTONIC SETTING OF SEDIMENTARY BASINS OF EASTERN INDONESIA: IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY
Authors: Shaw R.D. , Packham G.H.
Published: August 2017

The region east of the Sunda Craton, in Indonesia, formed during the past 50 million years as a consequence of interaction between the Southeast Asia, India–Australia and Philippine plates. These interactions were initially dominated by oceanic plate convergence but since the Miocene the overall northward movement of the India–Australia Plate, and with it the Australian continent, has led increasingly to convergence between oceanic and continental plates. The result has been the creation of a wide range of tectonic regimes and the development of twenty-three major sedimentary basins.Many of these basins exhibit indications of hydrocarbons, but most are frontier basins; several have not yet been drilled and only three have commercial production of oil. Gas production may be feasible soon in one other basin.The preferential occurrence of hydrocarbons in Southeast Asian basins of certain tectonic settings provides a basis for ranking the Eastern Indonesian basins. Seven distinct tectonic settings are represented. The foreland/rifted basins underlain by crust of continental affinity are considered to have the greatest hydrocarbon prospectivity whereas the fore-arc basins bordering the Celebes Basin and Molucca Plate are considered to have the least prospectivity.
SEQUENCE STRATIGRAPHY, BASIN-FLOOR FANS AND PETROLEUM PLAYS IN THE DEVONIAN – CARBONIFEROUS OF THE NORTHERN CANNING BASIN
Authors: Jackson M. J. , Diekman L. J. , Kennard J. M. , Southgate P. N. , O'Brien P. E. , Sexton M. J.
Published: August 2017

A sequence stratigraphic study of 4 000 kilometres of seismic data and fifty wells from the northern part of the Canning Basin has improved vasdy our knowledge of the evolution of the basin succession and has identified new petroleum play concepts. The Devonian to Lower Carboniferous succession can be subdivided into at least sixteen 'Vail type' sequences. This shows two contrasting phases of development; a reef complex in the Frasnian—Early Famennian, and a ramp in the Late Famennian-Tournaisian. The reef complex was characterised by reciprocal sedimentation with thick clastic lowstand wedges deposited in the Fitzroy Trough and thinner transgressive and highstand carbonate sediments deposited on the Lennard Shelf. The reef complex shows an early phase of backstepping, related to rapid drowning of the platform, and a later phase of marked progradadon when relative subsidence was lower. The ramp, in contrast, has only poorly developed lowstand wedges. Early ramp sequences are lenticular and successively offlap basinward; later sequences are more tabular and progressively onlap landward.Sequence stratigraphy has provided a new perspective on the setting and evolution of the traditional Devonian reef play. It emphasises the attractiveness of the Frasnian cycle of reef growth where source, seal and reservoir potential appear to be better than in the younger, much more extensively drilled Famennian cycle.New and untested stratigraphic targets have been identified in Famennian-Tournaisian highstand ramps and in lowstand fans. These new stradgraphic targets are generally basinward of the more traditional target areas and need to be assessed by either wildcat or stratigraphic drilling. The lowstand fans, especially, are large and extensive and favourably located to trap migrating hydrocarbons. Several prospects, each with the potential to contain in excess of 100 million barrels of recoverable oil, have already been identified on seismic data recorded basinward of the Lennard Shelf.
A SEISMIC AMPLITUDE VERSUS OFFSET STUDY IN THE SOLE AREA, GIPPSLAND BASIN
Authors: Spence K.W. , Ecclestone M.W. , Young I.M.
Published: August 2017

Analysis of amplitude versus offset (AVO) variations in shallow reservoirs can be a powerful tool, and has been used to determine the nature and distribution of hydrocarbons in the Sole area.The Sole-1 well was drilled in 1973 on the northern margin of the Gippsland Basin. The well encountered a 16 m dry gas column at the top of the Latrobe Group, within a fault-bounded anticline.Seismic line GS88B-97 was acquired in 1988 over the crest of the Sole Anticline. A dipping reflection event cross-cutting the geological structure was interpreted as a reflection emanating from the base of the gas column. Structural interpretation is ambiguous at the field's northern bounding fault and potential was recognised for a significant extension of the field northwards.An AVO study comparing variations in measured reflection amplitudes on common depth point (CDP) gathers and substacks with modelled results has been successful in unambiguously delineating the field extent and shows that the field is bounded to the north by the main fault. This successful use of AVO techniques at Sole has permitted a more precise estimate of gas in place and has potential for application to other accumulations along the northern margin of the Gippsland Basin.
THE SUPPRESSION OF VITRINITE REFLECTANCE IN SOME NORTH WEST SHELF WELLS: BARROW-1, JUPITER-1 AND FLAMINGO-1
Authors: Wilkins R.W.T. , Wilmshurst J.R. , Hladky G. , Ellacott M.V. , Buckingham C.P.
Published: August 2017

The sediments of the North West Shelf pose several problems for the accurate determination of thermal maturity by vitrinite reflectance. There are some serious discrepancies between the results of different workers; in some wells there is a surprisingly small increase of reflectance with depth, and it is sometimes difficult to honour these data in thermal maturity modelling. There appear to be two major sources of error in the reflectance data. These are firstly, the effect known as 'suppression' of vitrinite reflectance, and secondly, the difficulty of identifying the vitrinite population in dispersed organic matter.These problems may be addressed by the fluorescence alteration technique which is closely related to vitrinite reflectance but has two special advantages. Firstly, it depends on an analysis of the fluorescence alteration response of a small representative population of organic matter in which the individual macerals need not be identified. Secondly, anomalous vitrinites with suppressed vitrinite reflectance are readily characterized, and the corrected equivalent reflectances determined.The technique has been tested on three North West Shelf petroleum exploration wells, Barrow-1, Jupiter-1 and Flamingo-1. Major discrepancies between measured and equivalent vitrinite reflectance appear to originate in part from the difficulty of identifying the vitrinite population in dispersed organic matter from marine sediments. There is also evidence of suppression of vitrinite reflectance in most samples from Barrow-1, in the Flamingo Group and Plover Formation of Flamingo-1, and in the upper part of the Mungaroo Formation of Jupiter-1.A model is proposed to facilitate the assessment of measured vitrinite reflectance data from Carnarvon or Bonaparte Basin wells. Suppression effects are likely to have influenced measured vitrinite reflectance results from wells for which the strongest data are obtained from the Lower Cretaceous fluvio-deltaic Barrow Group sediments or their equivalents.
DEPLETION OF GAS RESERVOIRS BY MOLECULAR DIFFUSION — A CASE STUDY
Authors: Dunlop E.C. , Browne M.V. , Tadiar E.F.
Published: August 2017

Recent drilling in the southern Cooper-Eromanga basins of eastern central Australia has provided evidence to suggest that Permian gas reservoirs have been depleted by molecular diffusion.Diffusion is the process by which matter is transported along a concentration gradient, as a result of random molecular motion. It is a common and ubiquitous phenomenon in geological environments.In the Toolachee and Nappacoongee-Murteree blocks of PELs 5 and 6, channel sandstones of the Permian Patchawarra Formation are faulted or subcrop against the Murteree Horst basement high. The Lower-Middle Jurassic Hutton Sandstone was deposited directly over the exposed surface of this feature and the surrounding eroded Permo-Triassic topography. As a result, the truncated Patchawarra Formation sandstone reservoirs are in contact with the overlying Hutton Sandstone, a major fresh water aquifer within the Great Artesian Basin. There is an anomalous increase in Patchawarra Formation water resisitivity around the Murteree Horst, suggesting that fluid communication with the Hutton Sandstone has allowed ionic diffusion to reduce the salinity of the Patchawarra reservoirs.Fluid communication has existed between the Patchawarra and Hutton reservoir systems for the duration of hydrocarbon generation and migration. It is proposed that the diffusion of solution gas towards the Murteree Horst has lowered basinward Patchawarra gas concentrations below saturation point, to the extent that gas generated in nearby source areas has gone into solution rather than migrating in the gaseous phase to form accumulations. Hydrocarbon traps immediately basinward of the Patchawarra edge should contain gas only if the rate of supply from source rocks has been greater than the rate of loss by diffusion. Gas accumulations may be shielded from depletion by source areas or other accumulations which are closer to the Patchawarra edge.The diffusion model has a negative impact on the prospectivity of Permian gas targets in marginal source areas of the Cooper Basin where reservoir communication exists between potential gas reservoirs and the Great Artesian Basin aquifers. Nevertheless, the recognition of this process may be used to advantage in identifying areas where further gas exploration should be curtailed. Such action may improve the drilling success rate in the region.
TAXATION ASPECTS OF THE LIFE AND DEATH OF AN OIL AND GAS PROJECT
Authors: Thomas Colin G. , Minosora Michael J.
Published: August 2017

The taxation consequences affecting the birth, life and death of an oilfield have recently undergone substantial legislative changes. The purpose of this paper is to inform readers of these recent developments, particularly as they affect petroleum projects on the North West Shelf and the Timor Gap, and to critically appraise the strengths and deficiencies of the legislative approach, and provide recommendations for improvement.