bluuebunny/crossref_metadata_2025 huggingface dataset:
USE OF OIL AND GAS PLATFORMS AS HABITAT IN LOUISIANA'S ARTIFICIAL REEF PROGRAM
Authors: Kasprzak R. A. , Perret W.S.
Published: August 2017

Louisiana's offshore oil and gas industry began in 1947 when the first well was drilled out of sight of land south of Terrebonne Parish. Today over 3,700 offshore oil and gas platforms have been installed, supplying 25 per cent of the United States' production of natural gas and 12.5 per cent of its oil. In addition to meeting the world's energy needs, these structures also form one of the world's most extensive defacto artificial reef systems. However, federal regulations require that these structures be removed within 1 year after the lease is terminated. Disposal of obsolete offshore oil and gas structures is not only a net financial liability for private industry but can be a public loss of productive marine habitat. In 1986 the Louisiana Fishing Enhancement Act was signed into law, in response to the National Fishing Enhancement Act, creating the Louisiana Artificial Reef Program. This program was designed to take advantage of fishing habitat opportunities offered by these obsolete platforms. Since the program's inception 22 reef sites, utilising the components (jackets and decks) of 58 obsolete platforms, have been created off Louisiana's coast. The use of obsolete oil and gas platforms in Louisiana has proved to be highly successful. Their large numbers, design, longevity, and stability have provided a number of advantages over the use of traditional artificial reef materials. The participating companies also save money by converting the structure into a reef rather than abandoning it onshore; these companies are required to donate a portion of the savings to the state to run the artificial reef program. One disadvantage, however, is that the large size of these platforms restricts the distance to shore where they can be sited. To achieve the minimum clearance of 16 m over a submerged structure, as required by the Coast Guard regulations, the platforms must be placed in waters deeper than 30 m. Waters of this depth are found between 22 km and 115 km from shore on Louisiana's gently sloping continental shelf, making them almost inaccessible to many anglers. Funds generated by the program, however, can be used to develop reefs closer to shore if alternative low profile materials are used. Due to high maintenance costs of both the structure and aids to navigation, the increased liability exposure and the undetermined cost of removing the structure once it becomes a hazard to public safety and navigation, leaving the structures standing in place has thus far proved not to be a viable option in Louisiana.
ESTIMATED NET ECONOMIC BENEFITS FROM AUSTRALIA'S UPSTREAM OIL AND GAS INDUSTRY: 1980-2010
Authors: Hogan L. , Thorpe S. , Zheng S. , Trieu L. Ho , Fok G. , Donaldson K.
Published: August 2017

Australia's oil and gas resources industry has made a significant contribution to the Australian economy and is expected to continue to do so over the next 15 years and beyond. While oil and gas production from Bass Strait has been the most important part of the industry in the past, offshore oil and gas production has increased strongly in northwest Australia over the past decade. Future growth in the industry is expected to be mainly associated with further strong growth in gas production for both domestic use and the export market. This paper contains an assessment of some major net economic benefits from the exploration, development and production of Australia's oil and gas resources during the period 1980 to 2010.
NATIVE TITLE AND THE PETROLEUM INDUSTRY: RECENT DEVELOPMENTS, OPTIONS, RISKS AND STRATEGIC CHOICES
Authors: Altman J.C.
Published: August 2017

The Native Title Act 1993 (NTA) introduces a new dimension to Australia's land tenure systems; new property rights are established for native title parties via the creation of a 'right to negotiate' (RTN) with respect to future acts on land where native title might be determined. There is growing recognition that, legal uncertainties about the potential co-existence of native title on pastoral leases aside, there are elements of the NTA that are resulting in sub-optimal outcomes for the petroleum industry. Within a Coasian analytical framework it is demonstrated that owing to unclear property rights, transactions costs for negotiating exploration and production with native title parties are high. Recognising this, the Commonwealth government has proposed a package of amendments that attempt to address industry concerns while balancing these against indigenous interests. These recommendations include a once-only RTN, a higher threshold for registration of claims, automatic renewal of existing production leases and mandatory statutory functions for Native Title Representative Bodies (NTRBs) that will require them to resolve competing native title claims and to sign-off agreements with resource developers. Noting that strategic behaviour by industry, indigenous parties and especially State governments have hampered effective operations of the NTA, the paper ends by considering the choices available to the petroleum industry to ensure that statutory amendments are in its best interests.
APPROACHES TO IDENTIFYING RESERVOIR HETEROGENEITY AND RESERVE GROWTH OPPORTUNITIES IN THE HUTTON SANDSTONE, JACKSON FIELD, AUSTRALIA
Authors: Hamilton D. S. , Ryles P. G. , Lonergan T. P. , Hillyer M. G. , Holtz M. H.
Published: August 2017

An integrated geologic and engineering approach was applied to identify heterogeneities in the subsurface that might lead to reserve growth opportunities in the analysis of the Hutton Sandstone within the Jackson field, Eromanga Basin, Australia. The devised approach involves four key steps:determine geologic reservoir architecture;investigate trends in reservoir fluid flow;integrate fluid flow trends with reservoir architecture; andestimate original oil-in-place, residual oil saturation, and remaining mobile oil, to identify opportunities for reserve growth.Although the Hutton reservoir is interpreted as the deposit of a continental-scale bed-load fluvial system and is dominated by highly permeable sandstone, the genetic stratigraphic analysis identified numerous thin but widespread lacustrine shale units that periodically interrupted episodes of coarse clastic Hutton deposition. These shales represent chrono-stratigraphically significant surfaces, but more importantly, the trends established in reservoir fluid flow from monitoring aquifer encroachment, production response to workovers, and differential depletion indicate that these shale units act as efficient barriers to vertical fluid flow. Erosion of the upper part of the Hutton reservoir by the younger Birkhead mixed-load fluvial system caused further strati- graphic complexity introducing additional barriers to vertical and lateral migration of mobile oil and aquifer encroachment. These stratigraphic complexities were not fully appreciated in previous field development and production strategies and potential exists for incremental reserve growth through geologically-targeted infill drilling and recompletions.
THE GWYDION DISCOVERY: A NEW PLAY FAIRWAY IN THE BROWSE BASIN
Authors: Spry T. B. , Ward I.
Published: August 2017

The Gwydion-1 oil and gas discovery well is located in exploration permit WA-239-P on the sparsely explored Yampi Shelf area of the Browse Basin. The Gwydion feature was first recognised as a series of stacked seismic amplitude anomalies, which were interpreted to represent hydrocarbon-bearing Barremian to Albian age shallow marine sandstones draped over a prominent basement high. Amplitude versus offset analysis and modelling supported this interpretation.Gwydion-1 was spudded on 4th June, 1995, and discovered three gas bearing zones and one oil and gas bearing zone. The lowermost zone is Barremian to Hauterivian in age and consists of 12.6 m of net gas-filled glauconitic sand overlying a 9.5 m net oil-filled quartz sand. The three overlying hydrocarbon zones consist of glauconitic reservoirs of Barremian to Albian age.The play fairway for Gwydion-style traps has been named as the Echuca/Swan-Bathurst Island Group/Shelfal Play Fairway. It comprises mature Swan Group and Echuca Shoals Formation source rocks, and Bathurst Island Group reservoirs and seals. The limits of the play fairway on the shelf are controlled by the existence of topographic relief in the underlying basement metasediments. Migration pathway analysis suggests that the eastern margin of the Browse Basin is favourably situated to receive charge from the mature source rocks within the basin.The dominant northwesterly dip of the strata on the Yampi Shelf limits the potential for structural traps. Accordingly, a thorough understanding of the sequence stratigraphic architecture of the succession is necessary in order to generate the stratigraphic play concepts which hold the bulk of the prospectivity in the area.Gwydion-1 was plugged and abandoned as an uneconomic oil and gas discovery. It was, however, significant as it validated a new play type and generated renewed interest in the eastern margin of the Browse Basin for the first time since the mid 1970s; an area previously thought to be too shallow, too far from mature source and lacking reliable seal.
THE IMPACT OF INTEGRATED RESERVOIR CHARACTERISATION ON THE BUSINESS PERFORMANCE OF THE MODERN PETROLEUM COMPANY
Authors: Curtis A.A. , McCarthy J.F. , Balnaves C.
Published: August 2017

One emerging technology that has the capacity to significantly improve the way the petroleum industry undertakes its business is reservoir characterisation. Compelling business drivers for the adoption of reservoir characterisation by petroleum companies exist, including the reduction of project risk, the optimisation of reservoir performance, and the improvement of work practices, all of which can lead to far shorter project cycle times and better financial performance. Integrated Reservoir Characterisation has been successfully applied by one petroleum company following the implementation of a project designed to promote its adoption. A process description of Integrated Reservoir Characterisation applicable to the company was developed and this was used in the evaluation of computer applications to implement the concepts. The implications for both reservoir technology development and for training are considerable, with the latter being addressed by the use of case studies. The impact that Integrated Reservoir Characterisation is having, and is likely to have, on the business in terms of work practices, the treatment of uncertainty, and on real time well operations is such that it will feature far more prominently in everyday data management and analysis, interpretation and decision making. Integrated Reservoir Characterisation is a 'core-of-the-business' technology that has the potential to yield substantial bottom-line benefits if it is successfully advanced within the modern petroleum company.
PROSPECTIVITY AND EXPLORATION HISTORY OF THE BARROW SUB-BASIN, WESTERN AUSTRALIA
Authors: Baillie P.W. , Jacobson E.P.
Published: August 2017

The Carnarvon Basin is Australia's leading producer of both liquid hydrocarbons and gas. Most oil production to date has come from the Barrow Sub-basin. The success of the Sub-basin is due to a fortuitous combination of good Mesozoic source rocks which have been generating over a long period of time, Lower Cretaceous reservoir rocks with excellent porosity and permeability, and a thick and effective regional seal.A feature of Barrow Sub-basin fields is that they generally produce far more petroleum than is initially estimated and booked, a result of the excellent reservoir quality of the principal producing reservoirs.Structural traps immediately below the regional seal (the 'top Barrow play') have been the most successful play to date. Analysis of 'new' and 'old' play concepts show that the Sub-basin has potential for significant additional hydrocarbon reserves.
RESERVOIR POTENTIAL OF GLACIO-FLUVIAL SANDSTONES: MERRIMELIA FORMATION, COOPER BASIN, SOUTH AUSTRALIA
Authors: Chaney A.J. , Cubitt C.J. , Williams B.P.J.
Published: August 2017

Sedimentological analysis of cored sections within the Merrimelia Formation (basal Gidgealpa Group, Cooper Basin, S.A.) reveals a complex glacigenic environment, including glacio-lacustrine, deltaic, shorezone, fluvial, aeolian and other terrestrial facies. These facies are observed within terminoglacial and proglacial environments, and interfinger constantly throughout the Merrimelia Formation, exhibiting rapid environment change related to position of the ice sheet. Detailed sedimentological and petrological analysis, suggests that Tirrawarra sandstone-type facies belongs within the Merrimelia depositional realm. Provenance data indicates that the lithic component of the Tirrawarra Sandstone, is sourced from reworked Merrimelia coeval depositional facies. A high proportion of labile grains, which are commonly observed in the Merrimelia Formation, are only observed rarely in the Tirrawarra Sandstone (sensu stricto). It is proposed that the fluvial sandstones of the Merrimelia Formation are part of the same fluvial deposystem as the Tirrawarra Sandstone (sensu stricto) and the two sandstone sequences are the natural progression of coarsening sediment as more detritus was released from melting glaciers. It is suggested that there no longer remains any sedimentological, stratigraphical or petrographical reasons why the Tirrawarra Sandstone should not be included within the Merrimelia Formation. It is further proposed that all the braided glacio- fluvial sandstones within the Merrimelia Formation and Tirrawarra Sandstone (sensu stricto) be grouped together as 'Tirrawarra-type' facies within the Merrimelia glacigenic domain.The concept that the glacio-fluvial sandstones within the Merrimelia Formation are of the same genetic origin as the Tirrawarra Sandstone (sensu stricto), must point to the economic potential of similar sandstones found throughout the Merrimelia Formation. The thickness, sediment style and lateral extent of the proglacial braidplains is controlled by the duration of glacial melting. The Merrimelia Formation reveals a sequence of major freezing and thawing episodes with the overlying Patchawarra Formation representing the cessation of glacial influence in the Cooper Basin. Therefore, the youngest 'Tirrawarra-type' sandstone facies found at the top of the Merrimelia Formation is likely to contain the least amount of labile grains, a highly rigid siliceous framework and will be well sorted. The risk of lower reservoir quality increases down section where, with time, freezing dominated over thawing and the sediments were less rinsed, and where the resultant sandstones are more likely to be thin, more poorly sorted and chemically immature with a high proportion of labile framework grains. Thus compositional variation, controlling the diagenetic overprint, together with sandstone facies and bedform style exert profound control on the reservoir quality in the Tirrawarra-Moorari Field area, on potential gas reservoirs in the Merrimelia Formation.
FOCUSSING EXPLORATION IN THE OTWAY BASIN: UNDERSTANDING TIMING OF SOURCE ROCK MATURATION
Authors: Duddy I.R.
Published: August 2017

Quantitative reconstruction of the thermal and structural histories at key locations in the Otway Basin using an integrated approach based on AFTA® and vitrinite reflectance data reveals a regional pattern of elevated geothermal gradient prior to mid-Cretaceous cooling. Paleogeothermal gradients declined from −50 to 70°C/ km at −95 Ma to present day levels in the range −30 to 40°C/km by around 80 Ma. As a result, significant hydrocarbon generation must have occurred from the thick Late Jurassic to Early Cretaceous Otway Group section during the rapid rift-burial phase that preceded major mid-Cretaceous cooling.Regional decline in geothermal gradient in the Late Cretaceous leads to a 'two-stage' generation history for Otway Group source rocks because subsequent hydrocarbon generation did not recommence until the early maturation effects were overcome by greater Late Cretaceous and Tertiary burial. Such early, high heat flow is regarded as a feature of rift basins, and this results in an inverted pattern of hydrocarbon generation from rift source rocks that is here referred to as 'top-down generation', and which has a key influence on hydrocarbon prospectivity.Analysis of key hydrocarbon discoveries in the basin leads to the conclusion that all significant accumulations can reasonably be inferred to be sourced from the Otway Group, due to 'top-down generation5 delayed until the mid-Tertiary to present-day burial phase. This situation clearly favours hydrocarbon preservation in traps of a range of ages and has the added advantage of limiting the time available for traps to be breached in subsequent structuring episodes.This understanding of the decoupled relationship between the burial and thermal histories provides a sharp focus for further exploration of Otway Group-sourced accumulations, by defining areas with suitable thicknesses of the Late Cretaceous and Tertiary depositional packages which maximise the amount of re-generation since the mid-Tertiary.
A REVIEW OF THE PROSPECTIVITY OF THE CRAYFISH GROUP IN THE VICTORIAN OTWAY BASIN
Authors: Lavin C.J.
Published: August 2017

One of two major play fairways investigated by explorationists in the Otway Basin is the Crayfish Group system. This Tithonian-Barremian aged succession of syn-rift, continental siliciclastics was deposited in gra- ben distributed across the basin. All of the elements of a prospective petroleum province are present: lacustrine source rocks, high-quality quartzose sandstone reservoirs, and thick regional seals that are structured by both syn and post-rift tectonic events setting up a variety of play types.There has been a resurgence of drilling of Crayfish Group prospects in South Australia in the past decade. Some 24 wells penetrating the Crayfish Group have been drilled in South Australia during this period. This has resulted in the discovery of five commercial gas-fields, three non-commercial gasfields and two significant oil shows. Contrasting with this is the paucity of exploration for similar plays in the Victorian Otway Basin where, during the last decade, only six wells have penetrated the Crayfish Group, with one significant oil show recorded. With this in mind, the author has been searching for Victorian analogues of the successful Crayfish Group hydrocarbon discoveries in South Australia. This has involved defining the major Crayfish Group depocentres and evaluating their prospectivity.There are no less than 12 major Crayfish Group depocentres in the Victorian Otway Basin. Most have not been drilled, and those that are explored are rarely penetrated by more than one well. Good quality lacustrine source rocks are intersected on the flanks of these troughs and are also interpreted to exist in the troughs from seismic data. Reservoir sandstones are abundant in the Crayfish Group at a variety of stratigraphic levels in both South Australia and Victoria, as episodes of tec- tonism resulted in the influx of quartzose, high-energy fluvial sands into the Crayfish depocentres. Potential for oil and gas generation and entrapment is demonstrated for many of these graben.
PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN
Authors: Romine K. K. , Durrant J. M. , Cathro D. L. , Bernardel G.
Published: August 2017

A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.
THE RELATIONSHIP BETWEEN AUTHIGENIC KAOLINITE, RESERVOIR QUALITY AND TRAP HISTORY IN WONNICH-I
Authors: Storey J.M.V. , Hillock P.M.
Published: August 2017

A significant decrease in permeability is seen within the oil and water legs of the Wonnich-1 oil and gas discovery well in TP/8, despite an increase in porosity of 4-5 per cent by volume. The anomalous zone contains abundant authigenic kaolinite. The prompt integration of wireline log and core data allowed the presence of this kaolinite to be postulated at an early stage in the appraisal of the well. It also led to the proposal that the authigenic kaolinite was derived through the dissolution of detrital potassium feldspar and that its distribution was related to a palaeo-hydrocarbon contact. This hypothesis was used to design a tailored special core analysis and petrographic study including fluid inclusion, mercury injection and critical velocity analyses. The results confirmed the model and indicate that the bulk of the additional porosity within the anomalous zone is microporosity. In addition, the results show that where water is the flowing phase, the authigenic kaolinite becomes mobile at an interstitial velocity of approximately 4.4 jim/s. This equates to a water offtake rate of 5,700 BWPD, making kaolinite movement in the immediate vicinity of the well bore likely in any Wonnich oil development scenario. Pore throat sizes in the Wonnich reservoir appear to be sufficiently large that the kaolinite will pass through leading to an increase in permeability rather than a decrease. As a consequence, kaolinite movement is likely to lead to an increase in water production since it will occur preferentially in areas of water breakthrough.
RECENT ADVANCES IN THE SEQUENCE STRATIGRAPHY OF THE TRIASSIC TO LOWER CRETACEOUS SUCCESSION IN THE NORTHERN CARNARVON BASIN, AUSTRALIA
Authors: Jablonski D.
Published: August 2017

Application of sequence stratigraphy to well and seismic data has resulted in major revisions to the stratigraphic subdivision and understanding of the hydrocarbon system in the Northern Carnarvon Basin of Australia.A sequence stratigraphic nomenclature which integrates the biostratigraphic control and sequence terminology has been developed. This has proven to be an invaluable tool in enabling effective communication between geologists, biostratigraphers, and seismic interpreters. This nomenclature reduces the need to refer to absolute time scales and Epoch or Stage names, all of which are subject to change. The revised subdivision and new terminology can be used to reliably correlate across wide areas on the North West Shelf and possibly beyond.Six first and second order megasequences are recognised within the Triassic to Lower Cretaceous succession. These megasequences are mostly bounded by transgressive surfaces that are expressed on well logs as abrupt facies changes and on seismic as major downlap surfaces, indicating significant acceleration in subsidence rates and an increase in accommodation space in the basin. Each megasequence consists of an initial transgressive section of mainly fine-grained clastics overlain by a regressive and usually extensive succession of coarse-grained deposits. Recognition of the significance of these megasequence boundaries, and the stages of extension, has resulted in a vastly improved understanding of surfaces, some of which have previously been mis-interpreted as 'break-up unconformities'. Two distinct stratigraphic events, a Callovian transgression and an Oxfordian Iowstand, have been recognised as separate megasequence boundaries, which has a significant impact on the prospectivity of the Northern Carnarvon Basin.
COMPARISON OF PALAEOTEMPERATURE INDICATOR TECHNIQUES: AFTA, VR, FAMM AND ICA- CONSIDERATIONS FOR DESIGNING SAMPLING PROGRAMS
Authors: Foland S.S.
Published: August 2017

A comparison of thermal maturity techniques (AFTA, VR, FAMM and ICA) in a variety of geologic settings allows an assessment of the reliability of each technique and insight into basin thermal history. Five representative sample sets are presented. In the first set, well samples from southeast Asia yield a FAMM equivalent vitrinite reflectance (VRe) value of 0.53 per cent, significantly higher than the measured VR mean of 0.43 per cent. AFTA-derived VRe indicates expected maturity levels between 0.37 and 0.45 per cent. Petrographic evaluation identified a second vitrinite population composed of reworked material which may influence the FAMM result. In the second and third cases, outcrop and well samples of Woodford Formation from Oklahoma, USA, were analysed. Facies variability in these samples may have a greater influence on FAMM VRe results than on measured VR values and AFTA VRe. A sample of jet from England gave a FAMM VRe value of 1.0 per cent with comparable AFTA VRe greater than 0.70 per cent. Measured VR values occupy a narrow range and give a well-defined mean value of 0.26 per cent with strong petrographic evidence of geochemical suppression. Based on this evidence of vitrinite reflectance suppression, the FAMM VRe value appears to represent the actual maturity level. In the final suite, samples from the Otway Basin, Australia were analysed. Measured VR (1.19 per cent) and FAMM VRe (0.82 per cent) values are consistent with AFTA VRe which constrains the maturity to greater than 0.60 per cent. The liptinite-poor nature of this sample may cause an overcorrection calculation for the FAMM VRe value. In designing a thermal history study, collection of high-quality VR data including detailed maceral descriptions and qualitative fluorescence assessments should be completed first and then combined with other maturity techniques to define the timing and magnitude of thermal events.
COMPARISON OF PALAEO OIL CHARGES WITH CURRENTLY RESERVOIRED HYDROCARBONS USING MOLECULAR AND ISOTOPIC ANALYSES OF OIL-BEARING FLUID INCLUSIONS: JABIRU OIL FIELD, TIMOR SEA
Authors: George S.C. , Greenwood P.F. , Logan G.A. , Quezada R.A. , Pang L.S.K. , Lisk M. , Krieger F.W. , Eadington P.J.
Published: August 2017

Geochemical techniques have been used to compare the composition of oil trapped in fluid inclusions from the Jabiru oil field with currently reservoired oil. The inclusion oil is preferentially enriched in polar compounds, probably due to an adsorption effect during trapping, but this has not affected the hydrocarbon composition of the trapped oil. Source characterisation using biomarker and gasoline range hydrocarbon parameters shows that the fluid inclusion oils have the same source affinity as the current production oil. This is corroborated by the carbon isotopic compositions of high molecuJar weight n-alkanes trapped in oil-bearing fluid inclusions, which are similar to those of the production oil. Both oils have maturities in the peak oil generative window, but aromatic hydrocarbon ratios demonstrate that the fluid inclusion oil is less mature (calculated reflectance [RJ = 0.84 per cent) than the currently reservoired charge (0.92 per cent Rc). Fluid inclusion abundance data and residual oil saturations indicate the Jabiru oil column was previously significantly larger, with subsequent leakage reducing the column to its present size. The geochemical data collected for the fluid inclusion oil suggests that it is representative of early charge to the Jabiru structure. The difference between the fluid inclusion oil and the production oil is thought to reflect continued charging of the trap with progressively more mature oil from the same or similar source rock facies. The change in the molecular composition of the oil in the Jabiru structure probably occurred by dilution of earlier, lower maturity charge with larger volumes of more mature oil.
A MODIFIED FRACTURE GRADIENT RELATION AND ITS APPLICATION TO EAST TEXAS AND THE TIMOR SEA
Authors: Hillis R.R. , Crosby D.G. , Khurana A.K.
Published: August 2017

Theoretical fracture gradient relations are generally based on the assumption that the sedimentary sequence behaves elastically under conditions of lateral constraint. Hence the minimum horizontal stress (σhmin) is given by: where V is Poisson's ratio, σv is overburden stress, pp is pore pressure, and at is far -field tectonic stress. In driling practice, fracture initiation, or leak -off pressures, which are related to σhmin are most commonly predicted by the application of empirical stress /depth relations such as that proposed for offshore Western Australia by Vuckovic (1989): Leak -off pressure (psi) = 0.197D1145, where D is depth in feet. A modified form of the uniaxial elastic relation for the prediction of σhmin is proposed, such that: where the constants c and d are straight line regression constants derived from cross -plotting effective minimum horizontal stress and effective vertical stress. This relation, as opposed to previous empirical approaches to fracture gradient /σhmin determination, yields regression coefficients of physical significance: c represents the average Poisson's ratio term, v /(1 -v), and d represents an estimate of the tectonic (and inelastic) component of the minimum horizontal stress. This application of the modified fracture gradient relation, termed the effective stress cross -plot method, is tested successfully against published data from experimental wells in the East Texas Basin where independent estimates of Poisson's ratio are available. Leak -off pressures have been compiled from 61 wells in the Timor Sea. Leak -off pressures in the Timor Sea are somewhat lower than predicted by Vuckovic's (1989) stress /depth relation for offshore Western Australia, and a new, empirical stress /depth relation, which better fits the Timor Sea data is proposed: The effective stress cross -plot method is also applied to the Timor Sea data, yielding: Detailed pore pressure data were not available for the Timor Sea data -set and the effective stress cross -plot method does not fit the observed data any better than the new empirical stress /depth relation. However, the regression constants suggest an average Poisson's ratio of 0.26 and a relatively insignificant tectonic stress of 1 MPa for the Timor Sea.
WEST TUNA I BREAM B: APPLICATION OF CONCRETE TECHNOLOGY OFFSHORE AUSTRALIA
Authors: Titus P. G.
Published: August 2017

Esso/BHPP's West Tuna and Bream B Platforms are the first completed concrete-based platforms in Australia and are Exxon's first designed, built and operated concrete gravity structures (CGSs). Both platforms were towed to location, complete with commissioned topsides facilities, in fourth quarter 1996 and successfully installed in 61 m of water. They will add in excess of 45,000 BOPD (7200 kl/d) of oil production to Bass Strait volumes. West Tuna, with 48 well slots, will be Esso/BHPP's largest and most complex Bass Strait production facility, whereas Bream B will be an 18-slot, unstaffed minimum facility satellite platform with a 720-tonne topsides. By comparison, West Tuna's topsides weigh 7,300 tonnes.Esso/BHPP chose the CGS concept for the two developments following extensive conceptual studies with selected North Sea designers. Because of rising derrick barge day rates in the early 1990s (required for steel pile jacket installations), coupled with the availability of a suitable casting basin near Sydney, the CGS concept was judged economically attractive, with savings estimated at 10 per cent of the total facilities capital expenditure relative to its steel pile jacket alternative.The project saw a number of firsts, including the use of the world's largest land-based crawler cranes to lift and set the completed production modules over 75 m in the air onto the completed CGS structures. CGS fabrication productivity problems were experienced during the early phase of construction reflecting the complex nature of the construction, however implementation of a number of project management initiatives resulted in achievement of world-class productivity by completion of the works.
DECOMMISSIONING-AN ALTERNATIVE APPROACH
Authors: Goff H.B.
Published: August 2017

The traditional planning for decommissioning oil and gas projects has included the option to remove platforms from the project area leaving the site clear for other uses. However, decommissioning presents a number of opportunities for alternative uses for facilities that are relatively close to the coast and in developing areas.This paper examines the potential for the alternative use of facilities on the North West Shelf using the WMC operated Airlie Project as an example.Airlie Island presents an opportunity to conduct a number of research activities which would have the capability to enhance the understanding of the natural environment in the region and to gain better understanding of the long-term impact of the oil and gas industries impact on the natural environment. There is also the supplementary opportunity to conduct engineering research applicable to the oil and gas industry without the distraction and hazards of an operating field to interfere with the research projects. Allied to these possibilities is the potential to conduct research applicable to tourism and fishing related activities which are beginning to exert more pressure and the North West Shelf environment than has been the case in the recent past.In addition to the research opportunities, there exists the potential to manage Airlie Island as a support base for tourism activities on a commercial basis. The example presented could easily be applied to other projects nearing decommissioning.
ECONOMICS OF GAS FIELD DEVELOPMENTS IN THE COOPER BASIN AFTER 1999
Authors: McDonough R.C.M.
Published: August 2017

In February 1999 all Cooper Basin exploration acreage in South Australia, which has been under licence since 1954, will be relinquished and therefore become available to new explorers. To assist new explorers in evaluating exploration opportunities, Mines and Energy South Australia (MESA) has developed feasibility level costs for gas field developments which are independent of existing infrastructure owned by the Cooper Basin Joint Venturers. Alternatively, new producers may be able to negotiate access to existing facilities. MESA has developed estimated tolls based on pricing principles which imitate a competitive market. Tolls in this instance should lie between the operating cost of the facility as a minimum and the deprival value cost as a maximum.The study shows that if access to existing facilities is negotiated on a deprival value cost, fields with as little as 5 BCF (141 Mm3) recoverable raw gas are economic. However, if field development is totally independent of existing facilities, the minimum economic field size exceeds 35 BCF (987 Mm3) recoverable raw gas (assuming flaring of LPG is not permitted).MESA conducted this study based on data available in the public and commercial arenas. This demonstrates that it is possible for any company to develop their own data for development and negotiation purposes.
FORCE MAJEURE CLAUSES IN LONG-TERM GAS CONTRACTS (OR ARE THE FRENCH REALLY SMARTER THAN THE REST OF US?)
Authors: Sivyer J. M.
Published: August 2017

Force majeure clauses are a vital component of all long term gas contracts, whether relating to transportation or sale. The very nature of these contracts means that a consideration of a force majeure clause is virtually inevitable during the life of the contract. In addition, the clause applies to all phases of a gas project, from construction to purchase, supply, transportation and sale. The purpose of this paper is to examine the place that force majeure clauses have in the context of long term gas contracts, concentrating on the commercial and practical issues which need to be considered when negotiating them. It will also cover the potential that the principle of force majeure has to be used to the advantage of a party negotiating a gas contract.
IMPROVED LOG EVALUATION IN A LITHOLOGICALLY COMPLEX, GLAUCONITIC RESERVOIR—A CASE STUDY
Authors: Zhang Y.J. , Lollback P.A. , Salisch H.A.
Published: August 2017

This paper describes a case study of the application of an improved method of formation evaluation from well logs in a pilot area of the Mardie Greensand reservoirs in the Carnarvon Basin of Western Australia. They are lithologically complex reservoirs with a high and highly variable content of glauconite and extensive micro- porosity. These facts, in addition to the presence of other lithological components, make traditional log analysis, in particular the estimation of log-derived values of permeability, difficult if not impossible. The aim of this project was mainly to determine electrofacies and evaluate porosity and permeability from conventional well logs in this area. The sequential steps in the log evaluation of these glauconite-rich reservoirs were as follows: log quality control (borehole environmental corrections and depth matching); analysis of the log response characteristics; determination of litho- parameters used to identify the electrofacies; identification of the so-called hard streaks and their subsequent elimination for the purpose of reading log responses largely unaffected by these horizons; electrofacies identification and classification; porosity and permeability evaluation. The paper presents examples from several wells in the pilot area of the Mardie Greensand to illustrate this study.
THE APPLICATION OF STEREOSCOPIC VIDEO TO UNDERWATER REMOTELY OPERATED VEHICLES
Authors: Woods A.
Published: August 2017

A stereoscopic video system for use with Underwater Remotely Operated Vehicles (ROVs) has been developed by Curtin University's Centre for Marine Science and Technology. The system provides ROV operators with a fully three-dimensional (stereoscopic) view of the ROVs surroundings. This increased perception of depth offers several advantages to both the piloting of ROVs and also to the operation of an ROV manipulator arm.The stereoscopic video system consists of an underwater stereoscopic video camera which fits on the ROV and a stereoscopic display which is installed in the ship-based ROV control room. The system was developed in close cooperation with Woodside Offshore Petroleum which has used the system on their Triton ROV. Three ROVs are currently operated at Woodside's oil fields on Western Australia's North West Shelf.Field use of the system on the Triton ROV has revealed many advantages of stereoscopic video. One of the areas where advantages are particularly evident is in the operation of the manipulator arm. Operators have reported that it is perceptually easier to perform manipulator tasks. This is because the spatial relationship of objects can be immediately identified, making object placement and alignment easier. The system also provides a better understanding of the work site and a perceived improvement in image quality and therefore improved visibility.
A MULTI-DISCIPLINARY APPROACH TO DEFINITION AND CHARACTERISATION OF CARBONATE SHOALS, SHALLOW GAS ACCUMULATIONS AND RELATED COMPLEX NEAR-SURFACE SEDIMENTARY STRUCTURES IN THE TIMOR SEA
Authors: Bishop D.J. , O'Brien G.W.
Published: August 2017

A major exploration program is being undertaken by the AC/P16 Joint Venture in the central Timor Sea, northwestern Australia. Its safe and successful execution is critically dependant on the early definition and characterisation of both the numerous carbonate shoals in the area and the complex bathymetry. This was accomplished via the acquisition of environmental, high-resolution bathymetric, 2D and 3D seismic and airborne laser fluorosensor (ALF) data. Multi-disciplinary integration and analysis of these data have enabled mapping and 3D visualisation of the shoals, and the creation of a 3D velocity model for depth conversion. Seismic amplitude anomalies and chaotic seismic reflectors, which increase in areal extent toward the sea floor, have been interpreted as being due to shallow gas. These gas accumulations are also associated with soft-sediment gravity slides in the shallow sub-surface which exhibit thrust imbrication in the contractional toes and are linked to listric extensional faults. The high resolution bathymetric data have provided images of a disturbed sea floor in several of the areas which are affected by shallow gas: craters, troughs, ridges and mounds can be explained by the localised venting of gas at the sea floor. These gas accumulations are located above basin-scale faults, which are inferred to provide migration paths from more deeply buried source rocks. ALF anomalies mapped at the sea surface, and sea floor grab samples containing petrogenic hydrocarbons, also provide evidence that hydrocarbons are presently leaking from the sea floor.
SIDERITE AS A CONSTRAINT ON DEPOSITIONAL AND EARLY DIAGENETIC HISTORY: EXAMPLES FROM BARROW SUB-BASIN, NORTH WEST SHELF, WESTERN AUSTRALIA
Authors: Kraishan G. M. , Lemont N. M
Published: August 2017

Siderite cement is one of the most volumetrically important diagenetic minerals in the Late Triassic to Early Cretaceous sandstones of the Barrow Sub-basin. It constitutes up to 60 per cent of the rock volume, and where abundant, occludes the primary intergranular porosity. Petrogriiphic, chemical and isotopic studies indicate the early precipitation of much of this siderite prior to significant compaction. Siderite samples and concretions were taken from a variety of depositional environments ranging from fluvial to deep marine from Late Triassic to Early Cretaceous sequences.Of the early phases, three distinct siderite types were recognised and vary according to depositional environment. The first type, mostly collected from fluvial deposits, is Fe-rich with a mean composition of (Fe96.3 Mg1.8 Ca0.9 Mn1.0) C03. The second type of siderite cement is relatively Mg-rich, Ca-poor and has a higher Mn content, with a mean composition of (Fe87.1 Mg9.6 Ca1.2 Mn2.1) C03. The third type of siderite cement is typically Mg−, Ca-rich, with a low Mn content and an average composition of (Fe78.7 Mg12.4 Ca8.4 Mn0.5) C03. The second and third siderite cements occur in marine facies. The δ13C and δ180 values for siderite cements range from −2.8 to −14.3 %. PDB and 17.4 to 28.2 %. SMOW, respectively.Petrographic and chemical isotopic studies and other sedimentological data from siderite can be used to distinguish between different depositional environments. Chemical and isotopic compositions of the early authigenic siderites indicate precipitation from fluids with significant meteoric input. Siderite cements formed during sulphate reduction and early methanogenesis from mixed marine and meteoric pore-waters at temperatures below 30°C. While an influx of meteoric water to the fluvial and deltaic sediments of the Triassic Mungaroo Formation is easily envisaged, the siderites show that some mixing of sea water is also required. The concept of introduction of meteoric water to the marine sediments of the Birdrong Formation requires an appreciation of the sea level fluctuations at the time. In these situations, the recognition of meteoric or marine input to an early siderite cement can assist in the determination of sea level fluctuations.
LOO MA-1 REOPENS THE PALAEOZOIC PLAY IN THE SOUTH CANNING BASIN
Authors: King M R.
Published: August 2017

Looma-l was drilled as a wildcat exploration well targeting the Ordovician Nita Formation and Acacia Sandstone in EP 3S3 of the South Canning Basin. The main identified pre-drill risks and uncertainties were depth conversion/structural validity, presence of reservoir, reservoir quality and charge from an as yet unproven kitchen. The well tested interpreted structural closure in a broad, low relief anticline at three different levels, all of which were found to be hydrocarbon bearing. The primary objective Nita Formation and Acacia Sandstone both contain oil, and the secondary objective Nambeet Formation is interpreted to be gas bearing.Both the Nita Formation and Acacia Sandstone were fully cored and good oil shows, including live oil bleeding from core were encountered in both objectives. These hydrocarbon shows were substantiated by mud gas readings and petrophysical evaluation. Core analysis confirms the presence of live oil saturation in both objectives and the presence of limited permeability in the Acacia Sandstone. Drill stem testing was not successful in establishing any significant oil flow from either objective, however, gas to surface and oil-cut-water were recovered from the Acacia Sandstone. Core analyses corroboral ed the DST results, indicating that the reservoir quality of the Nita Formation and Acacia Sandstone is relatively poor at the Looma-l location. Depositional and diagenetic models indicate that potential for better reservoir development should occur further to the east of the Looma-l location.Looma-l has proven the presence of mature, migrated oils in both the Nita Formation and Acacia Sandstone and it is the first well in the South Canning Basin to unambiguously prove oil charge from a southern kitchen.