bluuebunny/crossref_metadata_2025 huggingface dataset:
A new generation inflow performance modelling tool with improved capabilities
Authors: Kabir Akim , Manolas Yvette
Published: August 2017

The inflow performance prediction of a completion is one of the most important tasks in forecasting production performance of a well. When selecting an optimum completion design it is essential to compare different options and perform parametric studies, one of the key completion decisions being the selection of a cased and perforated or barefoot well. In cased and perforated wells, key inflow performance parameters include gun type, perforation penetration depth, shot density, shot phasing, depth of mud invasion and dependence of their effects on reservoir properties. The open literature hosts a plethora of inflow equations for some classic completion practices; however, complex options are not adequately addressed. More importantly, when one compares inflow performance of various completion options or conducts a parametric study of certain parameters, the relative calculation results do not always make sense.
In this paper, we describe an operator’s (Shell International Exploration and Production) in-house study to develop a consistent set of inflow performance equations that not only make sense in their own right, but also make good relative sense when comparing different completion options, particularly with regard to cased and perforated wells. Most of the significant open literature has been reviewed and a set of consistent inflow models have been compiled and developed. Many equations have been improved—e.g., perforation skin calculations, mechanical and total skin calculations, rate dependant skin for horizontal completions—and new equations have been derived for options not previously modelled in the literature (e.g., barefoot and perforated completions, double perforated completions, re-perforated completions and complex horizontal completions). All equations have been coded into the Shell Perforation Optimisation Tool (SPOTTM) software package, enabling engineers to easily and accurately predict and compare complex completion options for design decisions. Inflow performance calculation results of various completion scenarios and parametric studies are also presented.
Improved oil recovery by raw water injection using horizontal wells
Authors: Bedrikovetsky Pavel , Wahab Mohammad Afiq ab , Chang Gladys , Souza Antonio Luiz Serra de , Furtado Claudio Alves
Published: August 2017

Injectivity formation damage with water-flooding using sea/produced water has been widely reported in the North Sea, the Gulf of Mexico and the Campos Basin in Brazil. The damage is due to the capture of solid/liquid particles by the rock with consequent permeability decline; it is also due to the formation of a low permeable external filter cake.
Yet, moderate injectivity decline is not too damaging with long horizontal injectors where the initial injectivity is high. In this case, injection of raw or poorly treated water would save money on water treatment, which is not only cumbersome but also an expensive procedure in offshore projects.
In this paper we investigate the effects of injected water quality on waterflooding using horizontal wells. It was found that induced injectivity damage results in increased sweep efficiency. The explanation of the phenomenon is as follows: injectivity rate is distributed along a horizontal well non-uniformly; water advances faster from higher rate intervals resulting in early breakthrough; the retained particles plug mostly the high permeability channels and homogenise the injectivity profile along the well.
An analytical model for injectivity decline accounting for particle capture and a low permeable external filter cake formation has been implemented into the Eclipse 100 reservoir simulator. It is shown that sweep efficiency in a heterogeneous formation can increase by up to 5% after one pore volume injected, compared to clean water injection.
A strategic perspective on oil and gas environmental assessment and approval
Authors: Heiden Karl
Published: August 2017

Proponents face a range of risks and uncertainties when undertaking oil and gas exploration and development activities. As well as the normal range of development and execution challenges, proponents also need to manage complex and varied external issues including stakeholder engagement and negotiations with government regulators.
There are numerous examples of oil and gas activities that have faced and are continue to face significant environmental and community issues resulting in schedule delays, impacts on reputation and increased costs. In some cases, these issues have been proved to be showstoppers, causing a major change in the proposed development or withdrawal of the proposal.
Regardless of how straightforward a proposed upstream oil and gas activity might be, there are typically many environment-related statues, regulations and guidelines that need to be satisfied before the development or activity can proceed. A systematic sequence must be followed for a proponent to negotiate their way through multiple application, consultation and approvals rounds. Interdependent approvals processes may run in parallel as a result of multiple jurisdictions. Project details may change and uncertainties or complexities identified part-way through the sequence, are problematic and can result in re-commencement of significant components of the sequence.
The sense of disquiet within the oil and gas industry, caused by the extensive environmental regulatory requirements, has not gone unnoticed by State and Federal Government agencies. Within the past 12 months, several reviews into key pieces of legislation and the overall regulatory burden imposed on the industry have been conducted and are continuing. These reviews have allowed industry to articulate their concerns and identify risks associated with the current legislative framework. It remains to be seen what the influence that this interaction has on review recommendations and ultimately on positive changes in practice.
This paper suggests that the use of a structured environmental approvals strategy is a key tool in meeting legislative requirements and the expectations of stakeholders while still being able to meet the challenges of changes to project design, timing delays and other unanticipated hurdles. This will be illustrated by examining an oil and gas proposal through a typical sequence of environmental approvals processes. It will draw attention to the complexity faced by the industry in seeking these approvals, and will highlight how a well-constructed, environmental approvals strategy can result in a better outcome for both the proponent and stakeholders.
Santos: The process safety management journey
Authors: Antony Andrew
Published: August 2017

Over the past five years Santos has introduced a new management discipline called process safety.
This has been achieved through formalising existing practices, particularly around reliability and maintenance strategy, as well as benchmarking against industry leaders to introduce other aspects such as process safety awareness, design and operating philosophies.
During the early 2000s Santos was focussed on establishing a company-wide environmental health and safety management system (EHSMS) and programs to build a safe and environmentally conscious culture.
For the first two revisions of its operation, the EHSMS contained safety standards relating to personnel hazards such as heat, driving, heights and chemicals. A vigorous audit program was introduced to assist all operating sites and activities, improving their systems to effectively manage environment, health and safety risks.
Santos now recognises that the establishment of a process safety culture involves five key aspects:

the right platform to build upon;
a separate identity, with specific standards defining requirements;
effective integration into existing processes;
audits dedicated to process safety that identify a baseline to measure against; and,
monitoring processes and personnel safety performance with equal interest.
A new seismic methodology to significantly improve deeper data character and interpretability on the North West Shelf
Authors: Long Andrew , Cambois Guillaume , Parkes Gregg , Mattsson Anders , Lundsten Terje
Published: August 2017

The sea-surface reflection generates interferences between up- and down-going waves that ultimately limit the bandwidth of marine seismic data. This phenomenon known as ghosting actually occurs twice—on the source side and on the receiver side. Ghost attenuation or elimination to increase the signal bandwidth has been the focus of extensive research. The receiver ghost can be removed using dual-sensor ocean-bottom devices (Barr and Sanders, 1989), a dual-sensor towed streamer (Carlson et al, 2007) or an over/under streamer acquisition (Brink and Svendsen, 1987). The over/under technique can also be used to remove the source ghost (Moldoveanu, 2000) but it requires flip-flop shooting of two sources at two different depths, ultimately halving the survey shot-point density. Alternatively, the source ghost can be attenuated using a beam steering technique originally developed some 60 years ago for dynamite land acquisition (Shock, 1950). The principle is to detonate charges at various depths in a sequence that constructively builds the down-going wave at the expense of the up-going wave. This way the energy of the ghost (the surface-reflected up-going wave) is reduced compared to that of the primary pulse. In this paper we adapt the beam steering approach to airgun arrays in the marine environment.
Moonfish M33a—planning and executing a challenging extended-reach drilling (ERD) well in the Bass Strait
Authors: Graham Tommy , Bransfield Jenny , McKerron Andrew , Robertson Sarah
Published: August 2017

The Moonfish Field is located in the Bass Strait/Gippsland Basin, 5 km north of the Snapper Platform. The structure is an inverted fault-bounded anticlinal closure, which has been modified by the emplacement of intrusive igneous stocks (volcanics) at depth. Hydrocarbons are trapped in stacked Cretaceous to Eocene fluvial clastics, with five major and numerous minor oil-bearing reservoirs. Whilst numerous coals 1–4 m thick are found throughout the entire non-marine section of this part of the basin, several thick and laterally continuous coals are found in the Eocene section. The N-1.4 Coal is 6 m thick and the N-1.9 Coal is 8 m thick over the Moonfish structure.
Coal seam gas in Australia's progression to a low carbon economy
Authors: Petersen Andrew , McKerrow Hugh
Published: August 2017

The previous decade has witnessed an unprecedented increase in societal appreciation for the existence of climate change and its associated impacts. One need only look to the reports of the Intergovernmental Panel on Climate Change (IPCC) for evidence—between 1990 and 2007, scientific acceptance of the anthropogenic nature of climate change has risen from merely perhaps in 1990 to a certainty of 90% in 2007.
As governments look to create imposts on the very emissions causing climate change, be it through emissions trading schemes (ETS) or through carbon taxes, an equally stark appreciation has occurred in relation to the need to switch to low emissions fuel source in the absence of carbon capture and storage. In contrast to the introduction of the EU ETS, fuel switching in Australia will be more problematic—now Australia sources only a small fraction of its energy supply from renewable energy sources and it will take some time for this to change. What is therefore needed, is a transition fuel—a fuel that will provide Australia with a stepping stone to a sustainable future while at the same time ensuring the security of our energy supply. Coal seam gas (CSG) could play an important part in this progression.
Its role is not, however, without its complexities. In a world of daily regulatory and market developments, the CSG industry will need to incorporate both Australian and international climate change issues into its development plans - its physical, reputational, regulatory and market risks and opportunities.
This extended abstract will examine the links between these exposures and the future growth potential of the industry.
Comparative geological setting of conventional oil and gas fields and CSG resources in the Surat/Bowen Basin, Queensland
Authors: Willink Rob
Published: August 2017

The Surat/Bowen Basin has long been of interest to explorers in pursuit of gas and oil in conventional reservoirs. Some 500 BCF of gas and 32 million barrels of oil have been produced from sandstones of Permian, Triassic and Jurassic age. Geochemical evidence suggests that these hydrocarbons were sourced almost exclusively from Permian coal measures, though a small contribution from Triassic coals cannot be discounted.
Primary interest in these basins today, however, resides in the exploration for, and commercialisation of, methane trapped in coal seams within the Permian and Jurassic successions. Total industry declared proven, probable and possible (3P) coal seam gas (CSG) reserves exceed 30 TCF, of which some 8 TCF are attributed to reserves in Permian coal seams, and 22 TCF in Jurassic coal seams.
With particular reference to a representative regional seismic traverse through the basin, this presentation will explain why known conventional and CSG fields in these basins are located where they are from a regional structural and stratigraphic perspective. The difference between the reservoir properties of coals and sandstones, and between the Permian and Jurassic coals will be discussed in terms of their maceral composition, gas content, adsorption capacity and thermal maturity. In addition, the location of known sweetspots within CSG fairways will be revealed.
The presentation will conclude with some speculative comments on what the future holds for both conventional and CSG exploration in these basins and will show that Origin Energy, in particular through its investment with Conoco Phillips in Australian Pacific LNG (APLNG), is well placed to participate in that future.
Victoria's Proterozoic basement controls the distribution of its southern margin petroleum basins
Authors: Taylor David , Moore David
Published: August 2017

There are three petroleum basins of differing character off the Victorian coast: the Otway, Bass and Gippsland basins. These formed during continental rifting between Australia, Antarctica and New Zealand, associated with the break up of Gondwana Marked variation in the development of these basins appears to have been largely controlled by the distribution of Proterozoic basement—the Selwyn Block—under central Victoria. Lying deep under central Victoria, this block surfaces towards the coast and continues southward as the Proterozoic crust of western Tasmania. The boundaries of this block are coincident with the boundaries separating the three basins.
The Otway Basin in western Victoria represents a clean break between Australia and Antarctica. The Otway Basin has thick fill upon thinned continental crust with an outboard break to a continent-ocean boundary. The overall geometry here is a classic lower plate margin.
This clean continental break-up failed to propagate eastward across the Proterozoic Selwyn Block. Instead, localised continental stretching resulted in some grabens and the overlying steers head sag of the Bass Basin. True continental separation was transferred southward to the margin of the Tasmania/Selwyn Block.
The Gippsland Basin lies east of the Selwyn Block. Its development reflects initial southern margin rifting, but this was overtaken by orthogonal-oriented Tasman rifting. This left the Gippsland Basin with a complex interplay of north-south and east-west structures controlling the platforms, terraces and deeps.
The Halyard gas discovery: a case study
Authors: Bevilaqua Carlo , Bingaman Paul T. , Dielesen Matthew S , Graham Kerry A. , Jennette David C.
Published: August 2017

The Halyard—1 exploration well discovered gas in a new and separate reservoir unit at the top of the Barrow Group along the outer margin of the Barrow Delta.
The well is located in WA—13—L, approximately 15 km northwest of the East Spar Field and 4 km east-northeast of the Spar—1 well. It was drilled in February 2008 and intersected 27.8 m of net gas pay in a Valanginian age Barrow Group reservoir interpreted to be a wave-dominated shoreface sandstone. The nearby Spar—1 well was drilled in 1976 and intersected 18.4 m of net gas pay in an older Barrow Group Sandstone within a distinctly separate, delta-front turbidite setting.
The Halyard and Spar fields are located within the overall confines of a structural closure at the Top Barrow Formation level. Earlier reservoir models dating back to the 1970s assumed connectivity between all permeable sandstones within the Top Barrow closure. Critical analysis and integration of all subsurface and engineering data sets inclusive of modular formation dynamics tester (MDT) pressures, condensate gas-ratios, production test data, post-drill amplitude variation with offset (AVO) modelling and seismic facies mapping, however, indicate these reservoirs are distinct and separate stratigraphic traps formed by successive, sequentially sealed depositional units within a larger delta slope edge sequence.
Collection of this data has yielded considerable insight into what historically have been viewed as simple traps. In our view and experience, the Barrow Group geology is much more complex with many traps typified by critical stratigraphic components in their trapping mechanism. The Halyard discovery is an example of the type of trap we expect to host much of the remaining reserve potential in the proximal Barrow Delta.
GEOLOGY OF THE OFF-SHORE AREAS OF NORTH-WESTERN AUSTRALIA
Authors: BOUTAKOFF N.
Published: August 2017

CONTOURING of Admiralty Chart No. 475 "North West Coast of Australia with the Off-lying Island and Reefs", 1928-1950, has revealed the existence of a number of offshore ridges along the outer edge of the Australian Continental Shelf. These ridges connect the coastal ranges of Exmouth Gulf in Western Australia with Sahul Banks, opposite Timor. Some of them are very large features and they are separated from the Continental Shelf by pronounced troughs. On the other hand, an even deeper trough separates them from the islands of Timor, Roti and Sawu. Other swells, rising almost to sea level, run parallel with them further out to sea. Geological comparisons are drawn which suggest that a deep stratigraphic section may be present in the general area where these ridges occur. Evidence is also presented to show that these features are tectonically and positively active, whereas the bounding troughs are in process of structural sinking. The size of some of these ridges, which approach the dimensions of the Lesser Sunda Islands, suggest that they are largely submerged and complex folded ranges, of which considerable parts are accessible to exploration. It is shown that these ranges all occur within the boundaries of Teichert's "Westralia Geosyncline". It is suggested that folding, intermediate in in tensity between the Alpine nappes of Timor-Roti and the gently warped sediments of the continental sedimentary basins of Australia, may be present in them.If so, these somewhat sharper folds may prove to be suitable for considerable accumulation of petroleum, as so often happens in the fore-front folds of other Alpine belts.
PETROLEUM PROSPECTS OF TASMAN AND GOLDEN BAY AREAS, SOUTHERN COOK STRAIT, NEW ZEALAND
Authors: Sprigg R. C. , Stockier W. F. , Braithwalte J. C.
Published: August 2017

Petroliferous sediments of Lower Tertiary age are preserved in a number of sub-basins, basin synclines and graben along the western portions of both islands of New Zealand.These form part of the extensively disrupted lineal and platform-like Cretaceous-Tertiary "West Basin" or geosyncline which is separated from a comparable "East Geosyncline" by the geanticlinal backbone of the New Zealand island-chain.Sedimentation in the West Basin was thick (10,000 to 20,000 feet or more) and continuous throughout much of the Cretaceo- Tertiary interval. Unconformities, where present, tend to be local features, but may still represent marked erosional and/or structural breaks. Lithologic and facies changes are not infrequent on a small scale, but these are superimposed on regional sequences that are traceable over the full longitudinal extent of the overall basin.Cretaceous to Lower Tertiary sequences tend to be freshwater and coal-bearing, but may be "paralic" locally. More marine facies are predicted beneath Cook Strait. Later Tertiary sediments are more predominantly marine, and include big thicknesses of mudstone and limestone.Oil seepages occur in a number of situations in the West Basin, and are associated with Lower Tertiary coal measures. In the Taranaki sub-basin the small oil field at New Plymouth has produced a total of 200,000 barrels of oil and 65 million cubic feet of gas, while the more recently discovered (1959) Kapuni condensate-gas field is capable of producing 60 million cubic feet of gas per day, of which 40 per cent is CO, accompanied initially by 4,500 million barrels per day of condensate.The Nelson and Farewell Spit sub-basins of present interest respectively plunge north beneath Tasman and Golden Bays on either side of the Pikikirunl Range "horst". They then coalesce beyond Separation Point and link with the Kapuni sub-basin beneath Cook Strait as part of the modern continental shelf. These graben-like developments are characterised by strong north plunge.Geophysical surveys leading to the better understanding of basin sub-structure about southern Cook Strait are discussed, followed by consideration of possible petroleum potential. Gravity anomalies in both the Tasman and Golden Bay areas, supported by seismic surveys, have confirmed anticlinal structure. Structural and stratigraphic traps for petroleum are predicted in relation particularly to these developments.
DIAPIRISM IN THE ADELAIDE GEOSYNCLINE
Authors: Coats R. P.
Published: August 2017

Approximately 20,000 feet of the Willouran Callanna Beds were deposited under shallow-water conditions in the western zone of the Adelaide Geosyncline. Diapirs were produced by the lower Callanna sequences. The initiation of diapiric growth is considered to be structural, but isostasy is thought to have played a subsequent role in the rise and emplacement of diapirs. Evidence for positive movements of diapir domes during deposition of Adelaide System and Lower Cambrian sediments is presented. The influence of diapiric emplacement on tectonics and sedimentation is described.
GEOLOGY OF THE NORTH-EAST MARGIN OF THE GREAT ARTESIAN BASIN QUEENSLAND, AUSTRALIA
Authors: Durkee Edward F.
Published: August 2017

The north-east margin of the basin as described herein comprises some 40,000 square miles situated regionally between the Bowen basin and the Drummond Range on the east and north-east respectively and the towns of Longreach, Charleville, and Mitchell on the west and south. The limit of the present-day Great Artesian basin in this area is marked by south-east striking outcrops of the Jurassic Precipice Sandstone.The stratigraphy of the area can be grossly subdivided into three time-rock units as follows:Pre-PermianPermian-TriassicLate Mesozoic and Tertiary.Pre-Permian rocks of importance include thick Devonian and Carboniferous units. Marine and evaporite facies are present in the Devonian in the south-west (Adavale basin), changing to more continental facies with volcanic and some marine incursions to the north-east (Drummond basin). Carboniferous units are dominantly paralic to continental types. The Devonian and Carboniferous systems were subjected to various degrees of pre-Permian tectonism and removal and, because of this, the existing occurrences of these systems are only fragments of their original extent. Permian and Triassic, marine to continental units were deposited across the area, thinning from east to west in possible cycles of transgression and regression. In addition to thinning regionally, these systems show marked variation in thickness due to transgression and drape and compaction over major, pre-Permian structural trends.Subsequent to deposition of the Triassic, a pronounced tectonic change was introduced. Previously negative areas to the north-east (Drummond basin—Springsure Shelf) began to rise and the Middle to Late Mesozoic subsidence and filling of the Great Artesian basin to the south-west commenced. Therefore, Triassic and Permian strata thicken regionally to the north-east under the Great Artesian basin margin, while post-Triassic strata thicken south-westward, in the opposite direction, into the basin.Three dominant structural trends are reflected in the sedimentary rocks of the area. These are:North-east trends under much of the Great Artesian basin margin.North-westerly trends of the Drummond basin to the north-east of the Great Artesian basin margin.Northern trends of the Denison trough east of the Great Artesian basin margin.
THE GEOLOGY OF THE BONAPARTE GULF BASIN
Authors: Brady T. J. , Jauncey W. , Stein C.
Published: August 2017

An estimated total of over 20,000 feet of Palaeozoic sediments accumulated in the Bonaparte Gulf Basin. The thickest known continuous section is that in Bonaparte No. 1 Well, abandoned at 10,530 feet in Upper Devonian sandstone and shale. Rocks of the Basin margins are mainly sandstones and limestones (in part reef), whereas a thick shale section has been discovered in the deeper parts. Data from recent seismic surveys indicate that the seaward extension of the Basin is considerable and that a thick pile of sediments is preserved there.The Bonaparte Gulf Basin formed as a result of subsidence of the north-eastern part of the Kimberley Block along fault lines associated with the Halls Creek Mobile Zone. This zone borders the south-eastern margin of the Basin and trends north-east. One basement block, represented by the presentday Pincombe Range, remained relatively high. The Bonaparte Gulf Basin can be divided into two subsidiary basins, the Carlton Basin to the west and north-west and the Burt Range Basin in the east and south-east. The Pincombe Range separates the two.Marine sediments were deposited in the Carlton Basin during the Middle and Upper Cambrian, Lower Ordovician, Upper Devonian and Lower Carboniferous epochs. Angular unconformities have been mapped between the Lower Ordovician and Upper Devonian rocks, and between Upper Devonian and Lower Carboniferous rocks. In the Burt Range Basin, deposition began in the Upper Devonian and continued with minor breaks through the Lower Carboniferous. Faults along the south-eastern margin were active through this period and affected the character of the sediments.Permian sediments are widely distributed and lie with unconformity on older units.
PALAEOGEOGRAPHY OF THE AUSTRALIAN PERMIAN IN RELATION TO OIL SEARCH
Authors: SPRIGG R. C.
Published: August 2017

Aspects of Permian glaciomarine sedimentation in Australia in relation to petroleum generation are treated in the light of the "Gondwana-land" hypothesis and recent studies in palaeolatitudinal distribution of Tertiary oilfields. The Permian segment of the Gondwana (U. Dev. to Trias.) succession is characterised by Glossopteris-Gangamopteris flora, glacial. glaciomarine and glaciofluvial sediments, coal measures and cyclothems.Evolution of the Hunter-Bowen Geosyncline of eastern Australia was accompanied by major volcanic activity along an arc-like archipelago. Sedimentation in this longitudinal ortho-geosynclinal belt linked acrosn the continent via shallow infra-basins and intra-cratonic basins to a series of graben-troughs (Perth, Carnarvon, Fitzroy and Bonaparte) developing about the western margin of Neo-Australia. These latter elongate and generally extremely deep "basins" were early manifestations of, and incipient riftings related to, the embryonic Indian Ocean.The Permian (south) palaeomagnetic pole was located approximately 30 degrees of are west of south from Melbourne, placing Australia in relatively high southern latitudes. Middle to Upper Tertiary oilfields of the Northern Hemisphere on the other hand have been indicated elsewhere to be products of tropical palaeolatitudes from which it has been implied that warm temperatures may be critical in oil formation.Recent investigations indicate that, acre for acre, Antarctic waters are potentially richer in organic life than any other. This is related primarily to abundance of nitrates and phosphates brought into sunlit (20 or more hours per day in summer) waters by upwelling currents. In consequence a high nutrient status of marine waters may be more important than palaeolatitudes in facilitating organic build-up in accumulating sediments. More research into contemporaneous sedimentation in relation to "Antarctic Convergence" in continental shelf settings is undoubtedly desirable.The great variety of Australian palaeo-environments of Permian age includes those of the open sea, continental shelf, hinge-line, barred embayment and alternating marine to fresh water basin. These offer a range of settings favourable to the entombment of organic matter under a variety of conditions presumed favourable to the formation of petroleum source-beds. Encouraging discoveries at Yardarino (W.A.), Gidgealpa (S.A.) and Cabawin (Qld.) justify accelerated exploration for commercial petroleum in the Australian Permian.
THE ROLE OF GEOLOGY IN RESERVOIR ENGINEERING
Authors: Hewitt C. H.
Published: August 2017

Every petroleum reservoir is the result of its own peculiar origin, as determined by provenance, depositional environment, and post-depositional history. These geologic factors control all properties generally thought of as reservoir properties—porosity, permeability (specific, relative, and directional), irreducible water saturation, water sensitivity, as well as continuity and homogeneity.The state of knowledge is such that in some cases rock and reservoir properties can be directly related; in others they can be related empirically or only through speculation and surmise.Once a reservoir has been discovered, the actual petroleum container can be cored, logged, and studied first-hand. Such a study should then guide field development through primary and secondary production. It can also aid materially in shaping an exploration approach for similar reservoirs and in influencing both wildcat and development drilling programmes.Each of the following examples of geologic reservoir studies was directed toward a different specific reservoir problem:A large anticline in Wyoming produces from several reservoirs of different age; each reservoir has a separate set of production characteristics and problems.A pair of structural-stratigraphic traps in Illinois, although similar in some properties, have different origin, internal geometry, heterogeneity, and recoverable reserves.A gas condensate reservoir in Oklahoma where a combined petrographic-relative permeability study led to the installation of a dry-gas repressuring plant and a marked increase in recoverable reserves.Although these examples are all from U.S. oilfields, the principles and methods of study are applicable in any petroleum province. Best conservation practices require the integration of geologic reservoir studies into drilling, logging, completion, stimulation, and primary or supplementary recovery operations.
REGIONAL PHOTOGEOLOGY OF THE IPSWICH BASIN-ESK TROUGH, QUEENSLAND
Authors: Jorgenson Jon T. , Barton Robert H.
Published: August 2017

The Ipswich Basin-Esk Trough Area of south-eastern Queensland was mapped photogeologically with the main emphasis on extending a uniform Jurassic sequence from the Surat Basin located to the west into the area under discussion. The photogeologic units are correlated with the Jurassic Hutton, Evergreen and Precipice formations. The remaining photogeologic units within the Ipswich Basin-Esk Trough Area are correlated with the previously established stratigraphic nomenclature.The structural interpretation agrees regionally with the basic tectonic framework as summarised by Hill (1961). The northern part of the Esk Trough is interpreted to be a westward tilted, compressed fault block. The resulting regional surface structure of the Esk Trough consists of two main synclines separated by a fault zone.The Triassic Esk Trough is unconformably overlapped to the south by the Jurassic rock sequence of the Ipswich Basin. The nature and southern extent of the Esk Trough under the Ipswich Basin is not known. The steeply dipping Mesozoic sequence located immediately west of the town of Ipswich and the asymmetric, faulted, South Moreton Anticline are both on trend with the eastern boundary of the Esk Trough and probably are tectonically related to it. An alignment of igneous intrusives in the south-western part of the Ipswich Basin may be controlled by a southerly trending surface extension of the tectonic line forming the west edge of the Esk Trough.
THE GEOLOGY OF WESTERN PAPUA
Authors: Rickwood F. K.
Published: August 2017

Two principal phases of sedimentary deposition are known in Western Papua, the Mesozoic and Tertiary. Knowledge of older sediments is limited to a small outcrop of Permian on the western end of the Kubor Range beneath which are granites and metamorphic rocks forming basement.The Mesozoic rocks outcrop in the central ranges of New Guinea and have been penetrated in 20 wells in the southern coastal area. Elucidation of the detailed Mesozoic structure and stratigraphy is incomplete but the outline of the history of sedimentation is emerging and appears to be similar in broad structural pattern to that of the overlying Tertiary sequence.Folding emergence and erosion occurred at the end of the Mesozoic in response to epeirogenic uplift of the northeastern margin of the Australian continent; with the subsequent Tertiary transgression being represented for the most part by Eocene and Oligocene limestones of limited thickness. On the basis of facies characteristics and sediment thickness it appears that during the Miocene western Papua was the site of an arcuate orthogeosynclinal complex. In the sector north of tilte Papuan Gulf the subdivision into a eugeosynclinal and miogeosynclinal trough is clearly represented by the development, in Kereruan times, of the Aure Trough and the Omati Basin. During the Lower and Middle Miocene huge thicknesses of greywackes and shales were deposited in the Aure Trough and westwards and southwestwards of the trough a limestone succession consisting mainly of basinal, fore -reef limestones and shoal reefs was developed over an area some 200 miles wide with its maximum thickness at Ornati. Definition of limestone facies within this huge limestone area is still incomplete. The Upper Miocene was marked by widespread development of argillaceous and arenaceous facies with only minor development of limestone. Movements during the Upper Miocene led to restriction of the Pliocene basin of sedimentation and the formation of shallow water arenaceous rocks with lesser mudstones and coals. The final major phase of folding and uplift probably began in late Pliocene times and has continued to the present day, accompanied by vulcanism and vigorous erosion.
EXPLORATION IN THE OTWAY BASIN
Authors: White A. H.
Published: August 2017

Petroleum exploration in the Otway Basin recently entered a new phase with the extension of the search to offshore areas. Marine seismic surveys carried out in PEP.22 outlined several structures, three of which were drilled in 1967 by the semi-submersible platform SEDCO 135E. The results of the drilling programme are discussed in this paper.
PETROLEUM EXPLORATION OUTLOOK FOR 1968
Authors: Williams L. W.
Published: August 2017

To change is expected in the trend which has developed over the last few years towards increasing interest in offshore areas, and in Papua-New Guinea.The overall expenditure on petroleum exploration in Australia and Papua-New Guinea during 1968 will be approximately the same as in 1967.Because of the greater expense which will be incurred through the increased use of offshore drilling vessels, a reduction in other exploration activities is expected. This reduction will occur mainly in geophysical operations and the biggest reduction will be in seismic surveys on land.
ANALYSIS OF CAPITAL EXPENDITURE PROPOSALS IN THE PETROLEUM INDUSTRY
Authors: Bills Geoffrey
Published: August 2017

BECAUSE of the characteristics of the decisions and the nature of the industry, this is especially true of the management of capital expenditure in the petroleum industry. Much progress has been made, however, in the development and application of good analytic techniques for measuring the relative attractiveness of various investment proposals. These include the use of the present value concept to take account of the time pattern of future benefits and of probability theory to handle the problems of risk and uncertainty. The concept of strategy and its effective application to a business is also needed to give purpose and direction to the whole capital expenditure programme. That strategy may be even more important than fine analytic tools is illustrated by some examples of Texaco's success.“Management,” said Peter Drucker, “is the art of doing the impossible with intelligence.”At first sight this statement may seem merely clever. On reflection it turns out to be true. I hope to show that, for the management of capital expenditure in the petroleum industry, it is profoundly true, and that its truth holds some important lessons.
GEOLOGICAL FRAMEWORK OF THE CONTINENTAL SHELF OFF NORTHWEST AUSTRALIA
Authors: Lofting R. G. Mollen R. W. Craig M. J. W.
Published: August 2017

A simplified synthesis of exploration results in permits covering a large area of the broad continental shelf off northwest Australia (between Bathurst Island, N.T. and the Monte Bello Islands. W.A.) is presented and a preliminary analysis of the geological framework of the shelf is offered. Companies with working interests in these permits are B.O.C. of Australia Limited. Shell Development (Australia) Pty. Ltd., Woodside (Lakes Entrance) Oil Co. N.L., Mid-Eastern Oil N.L., B.P. Petroleum Development Australia Pty. Ltd. and. in the permits In Western Australia, California Asiatic Oil Co.Reconnaissance aeromagnetic and seismic surveys have provided evidence of substantial thicknesses of sedimentary rocks, and revealed the presence of several major structural/ depositional features. The geological significance of these features has been partly rationalized by the integration of stratigraphic and seismic data, and by interpolation of established onshore geology. Ashmore Reef No. 1 revealed a substantially complete Tertiary-Upper Cretaceous carbonate- clay sequence, a thin early Cretaceous-late Jurassic section, containing detritus from underlying Upper Jurassic basic lavas, and part of a thick Triassic sedimentary sequence. Legendre No. 1 penetrated Tertiary, Cretaceous, and Jurassic sedimentary sequences, with gross stratigraphic similarities to sequences in parts of the Carnarvon basin.The shelf has a block-faulted basement substructure of Precambrian rocks, related in part to the extension of major structure in Precambrian rocks of the northwest Australian mainland. The geological superstructure of the shelf consists of Phanerozoic rocks whose essential structural framework is related to rejuvenated Precambrian structure. Warped and faulted Phanerozoic sequences have two major strike components, one sub-parallel and the other sub-normal to the present coastline. The effects of tectonics on sedimentation are outlined.
THE NAPPAMERRI FORMATION
Authors: Papalia N.
Published: August 2017

The name, Nappamerri Formation, is proposed for the Triassic section within the Cooper basin of South Australia and Queensland. Four separable rock units comprise the Nappamerri Formation and are classified as members. The formation was deposited in an essentially continental-fluvial environment. Except locally, the Nappamerri Formation conformably overlies the Permian, Gidgealpa Formation and is in turn, unconformably overlain by the Hulton Sandstone of Jurassic age. The extent of the Nappamerri Formation approximates the limits of the Cooper basin and the thickness of this formation ranges to over 2.500 feet in the deeper parts of the basin.
SEISMIC DATA PROBLEMS ON COASTAL LIMESTONE, W.A.
Authors: Taylor D. D.
Published: August 2017

The surface Coastal Limestone in the Perth basin extends from Cape Leeuwin in the South to Geraldton in the north forming a strip along the coast up to 15 miles wide. Over a great portion of this area the reflection seismic results are unreliable. Seismic studies on the limestone disclose some aspects of the problem and indicate ways to improve the quality of the data.
THE PHYSICAL PROPERTIES OF GIPPSLAND BASIN HYDROCARBONS
Authors: Stewart W. J.
Published: August 2017

Since the beginning of offshore drilling in the Gippsland basin, during 1964, hydrocarbon accumulations have been encountered in nine of the eleven exploration wells drilled. Commercial gas fields have been proved at Barracouta and Marlin with estimated total recoverable reserves of 5.3 Tcf wet gas. The Halibut and Kingfish fields are estimated to contain total recoverable reserves of 1,500 million barrels of oil. Minor accumulations of oil have been encountered at Barracouta and Marlin and are presently being evaluated. Other accumulations, presently considered non-commercial, were found in the Dolphin and Perch fields. Recent discoveries in the Snapper, Tuna and Flounder fields are yet to be appraised.Generally, analyses of gases discovered in the Gippsland area show them to be of good quality with a methane content in the order of 80-85%. Hydrogen sulphide of 45-50 ppm has been found in the Barracouta gas but only a trace has been reported in the Marlin gas. Commonly, the percentage of non-hydrocarbons in the gas is low in the shallower horizons but appreciable quantities exist In accumulations encountered at depth.Oils are generally of low sulphur content and range in gravity from 40° API to 64° API. Gas-Oil ratios of from 100 to 1,100 cu.ft./bbl have been measured in crudes which range from highly under-saturated to saturated. The oils are of the light variety and yield high proportions of gasoline and kerosenes and small quantities of residues. Wax contents of the crudes range from very low to 27% and pour points from —80° to 75°F.
THE ROLE OF CHANCE IN EXPLORATION
Authors: Chapman Richard E.
Published: August 2017

In the early stages of speculative mining ventures, when extrapolation of scanty data is unavoidable, the role of chance can be at least as important as that of professional skills.Having drilled n consecutive successful wells without a failure, at what point can it be said that the chances of ultimate failure of the venture are negligible?Conversely, having drilled n consecutive failures, at what point can it be said that the chances of ultimate success are unacceptably remote?Having estimated the area required to be underlain by hydrocarbons for a venture to be profitable, how many wells should one be prepared to drill to ensure at least one success with a specified probability?Defining Relative Area as the area underlain by what is sought, expressed as a fraction of the total area of interest, the probability of success in a well drilled at random is precisely this Relative Area.Drilling may be regarded as random if the outcome of a well cannot be predicted. When the goal of the geologist — the construction of a deterministic model — has been achieved, the drilling is not random and the methods of this paper are not valid.When all n wells drilled so far have been successful, the minimum-likely Relative Area is given by where p is the probability of success and also the Relative Area (0 ≤ P ≤ 1); P is the degree of confidence required (0 When all n wells have been failures, the maximum-likely Relative Area is given by If a specified Relative Area p' exists, the minimum number of wells required to ensure at least one success is given by the nearest integer n that satisfies the inequality When some wells have been successful and others failures, the probability of exactly r successes (irrespective of order) in a total of n wells is This may be of little value when n is small. But when n is large (say 20 or more), and when 'success' refers to the finding of something that did not influence the siting of the wells (such as the presence or absense of a particular facies), then the probable range of the Relative Area is given by where z may be taken as 1.6 for 90 percent confidence, and 2.0 for 95 percent confidence.These relationships are aids to geological judgement, not substitutes for it.
EXPLORATION AND GEOLOGY OF THE ARAFURA SEA
Authors: Nicol G. N.
Published: August 2017

Large scale systematic exploration of the Arafura Sea started in 1965. Following an aeromagnetic survey some 4,900 miles of seismic lines have been shot by Shell in their permits, which at present occupy almost 60 percent of the total acreage.The following results have been obtained:Possible Palaeozoic sediments and certain Mesozoic and Cenozoic sediments are present in the Arafura Basin, deposited on a strongly folded and faulted pre-Cambrian basement. The Mesozoic and Cenozoic overlies the pre-Mesozoic with regional unconformity.Sedimentary thicknesses gradually increase offshore to more than 20,000 feet.During Mesozoic and Cenozoic times the Arafura Basin was affected by more or less continuous subsidence, which resulted in very little deformation. Only one small closed structure, in the Money Shoal area, has been defined.Stronger pre-Mesozoic movements, which resulted locally in the formation of a westnorthwest-eastsoutheast trending graben, are evident. Structural leads in this graben might result in possible Palaeozoic fault traps. However, the presence of Palaeozoic sediments is speculative and the structures in the graben appear to have been strongly eroded prior to the deposition of the Mesozoic.In addition to structural traps, stratigraphic trapping possibilities show some promise.
PETROLEUM EXPLORATION ACTIVITY REPORT AND PREDICTIONS
Authors: Williams L. W.
Published: August 2017

In 1969, there were indications of increasing exploration activity onshore in Australia. This is expected to continue and strengthen during 1970.The results obtained during 1969 were not very encouraging although gas reserves were increased and there was one significant new gas discovery. There were no large oil discoveries.Exploration expenditure is expected to be about the same as for the last two years, but with an increased percentage to be spent onshore.The present level of expenditure is not likely to be sufficient to find the reserves necessary to achieve continuing selfsufficiency for Australia.
LEGAL, LOGICAL, AND GEOLOGICAL BOUNDARIES OF THE AUSTRALIAN CONTINENT
Authors: Glaessner M. F.
Published: August 2017

A consideration of the judgement of the International Court of Justice in the North Sea Case in 1969 shows that the outer boundary of a country bordering on the ocean encloses those areas under the sea which constitute a natural prolongation of its land territory. The Geneva Convention of 1958 had defined jurisdiction over the Continental Shelf as bounded by the 200 metre line or beyond that line to the limit of exploitability of natural resources. Recent advances in deep sea mining and drilling have raised fears of a race for submarine claims or of an uncontrolled expansion of national borders to midlines of oceans, unless new conventions or treaties are agreed upon. The equidistance principle applies only as a means of equitable apportioning of shelf areas between nations whose territories adjoin the same shelf.Where a country faces the ocean, neither distance nor depth or flatness or declivity of the ocean floor can provide a basis for drawing the outer limits of its jurisdiction. On the basis of the principle of natural prolongation and taking into consideration the fact that the crust of the earth under the continents is different from that under the oceans, it is proposed that geophysical measurements together with bathymetry indicative of underlying crustal structure, rather than arbitrary frame lines should be used for the determination of the boundaries between Australia and the deep ocean, with due allowance for possible local complexities.