bluuebunny/crossref_metadata_2025 huggingface dataset:
Distinguishing mechanisms for alternans in cardiac cells using constant-diastolic-interval pacing
Authors: Cherry Elizabeth M.
Published: August 2017

Alternans, a proarrhythmic dynamical state in which cardiac action potentials alternate between long and short durations despite a constant pacing period, traditionally has been explained at the cellular level using nonlinear dynamics principles under the assumption that the action potential duration (APD) is determined solely by the time elapsed since the end of the previous action potential, called the diastolic interval (DI). In this scenario, APDs at a steady state should be the same provided that the preceding DIs are the same. Nevertheless, experiments attempting to eliminate alternans by dynamically adjusting the timing of pacing stimuli to keep the DI constant showed that alternans persisted, contradicting the traditional theory. It is now widely known that alternans also can arise from a different mechanism associated with intracellular calcium cycling. Our goal is to determine whether intracellular calcium dynamics can explain the experimental findings regarding the persistence of alternans despite a constant DI. For this, we use mathematical models capable of producing alternans through both voltage- and calcium-mediated mechanisms. We show that for voltage-driven alternans, action potentials elicited from a constant-DI protocol are always the same. However, in the case of calcium-driven alternans, the constant-DI protocol can result in alternans. Reducing the strength of the calcium instability progressively reduces and finally eliminates constant-DI alternans. Our findings suggest that screening for the presence of alternans using a constant-DI protocol has the potential for differentiating between voltage-driven and calcium-driven alternans.
An enhanced catastrophe theory that explains turbulence
Authors: Blaustein Rich
Published: August 2017

A group of Chinese engineering researchers combine chaos theory and dimensionless analysis to explain the lead-up and abrupt onset of turbulence.
MAPPING THE PLATE TECTONIC RECONSTRUCTION OF SOUTHERN AND SOUTHEASTERN AUSTRALIA AND IMPLICATIONS FOR PETROLEUM SYSTEMS
Authors: Norvick M.S. , Smith M.A.
Published: August 2017

Southern Australian breakup history is divisible into three phases. The first phase began with Callovian (c.159–165 Ma) rifting in the western Bight Basin. During the Tithonian (c.142–146 Ma), rifting extended eastwards into the Duntroon, Otway and Gippsland Basins. By the Valanginian (c.130–135 Ma), ocean crust formed between India and western Australia. Structural style in the western Bight changed to thermal subsidence. However, fluvio-lacustrine rift sedimentation continued in Duntroon, Otway and Gippsland until the Barremian (c.115–123 Ma) when these basins also changed to thermal subsidence. The diachronous progression of basin fill types produces a progressive shift in ages of potential source, seal and reservoir intervals along the margin.The second phase began during the Cenomanian (c.92–97.5 Ma) with uplift in eastern Australia, stress reorganisation and divergence of basin development. The Otway, Sorell and Great South Basins formed in a transtensional regime. These tectonics resulted in trap generation through faulting, inversion and wrenching. During the Santonian, oceanic spreading began in the southern Tasman Sea (c.85 Ma). Slow extension caused thinning of continental crust in the Bight and Otway Basins and subsidence into deeper water. Ocean crust formed south of the Bight Basin in the Early Campanian (c.83 Ma) and also started extending up the eastern Australian coast.The third stage in development was caused by Eocene changes to fast spreading in the Southern Ocean (c.44 Ma), final separation of Australia and Antarctica, and cessation of Tasman Sea spreading. These events caused collapse of continental margins and widespread marine transgression. The resultant loading, maturation and marine seal deposition are critical to petroleum prospectivity in the Gippsland Basin.
GEOLOGY AND HYDROCARBON POTENTIAL OF THE SOUTHERN GEORGINA BASIN, AUSTRALIA
Authors: Ambrose G.J. , Kruse P.D. , Putnam P.E.
Published: August 2017

The Georgina Basin is an intracratonic basin on the central-northern Australian craton. Its southern portion includes a highly prospective Middle Cambrian petroleum system which remains largely unexplored. A plethora of stratigraphic names plagued previous exploration but the lithostratigraphy has now been rationalised using previously unpublished electric-log correlations and seismic and core data.Neoproterozoic and Lower Palaeozoic sedimentary rocks of the southern portion of the basin cover an area of 100,000 km2 and thicken into two main depocentres, the Toko and Dulcie Synclines. In and between these depocentres, a Middle Cambrian carbonate succession comprising Thorntonia Limestone and Arthur Creek Formation provides a prospective reservoir-source/seal couplet extending over 80,000 km2. The lower Arthur Creek Formation includes world class microbial source rocks recording total organic carbon (TOC) values of up to 16% and hydrocarbon yields up to 50 kg/tonne. This blanket source/seal unconformably overlies sheetlike, platform dolostone of the Thorntonia Limestone which provides the prime target reservoir. Intra- Arthur Creek high-permeability grainstone shoals are important secondary targets.In the Toko Syncline, Middle Cambrian source rocks entered the oil window during the Ordovician, corresponding to major sediment loading at this time. The gas window was reached prior to structuring associated with the Middle Devonian-Early Carboniferous Alice Springs Orogeny, and source rocks today lie in the dry gas window. In contrast, high-temperature basement granites have resulted in overmaturity of the Arthur Creek Formation in the Dulcie Syncline area. On platform areas adjacent to both these depocentres source rocks reached peak oil generation shortly after the Alice Springs Orogeny; numerous structural leads have been identified in these areas. In addition, an important stratigraphic play occurs in the Late Cambrian Arrinthrunga Formation (Hagen Member) on the southwestern margin of the basin. Key elements of the play are the pinchout of porous oil-stained, vuggy dolostone onto basement where top seal is provided by massive anhydrite while underlying Arthur Creek Formation shale provides a potential source.
DEEP BASIN GAS: A NEW EXPLORATION PARADIGM IN THE NAPPAMERRI TROUGH, COOPER BASIN, SOUTH AUSTRALIA
Authors: Hillis R.R. , Morton J.G.G. , Warner D.S. , Penney R.K.
Published: August 2017

Deep basin hydrocarbon accumulations have been widely recognised in North America and include the giant fields of Elmworth and Hoadley in the Western Canadian Basin. Deep basin accumulations are unconventional, being located downdip of water-saturated rocks, with no obvious impermeable barrier separating them. Gas accumulations in the Nappamerri Trough, Cooper Basin, exhibit several characteristics consistent with North American deep basin accumulations. Log evaluation suggests thick gas columns and tests have recovered only gas and no water. The resistivity of the entire rock section exceeds 20 Ωm over large intervals, and, as in known deep basin accumulations, the entire rock section may contain gas. Gas in the Nappamerri Trough is located within overpressured compartments which witness the hydraulic isolation necessary for gas saturation outside conventional closure. Furthermore, the Nappamerri Trough, like known deep basin accumulations, has extensive, coal-rich source rocks capable of generating enormous hydrocarbon volumes. The above evidence for a deep basin-type gas accumulation in the Nappamerri Trough is necessarily circumstantial, and the existence of a deep gas accumulation can only be proven unequivocally by drilling wells outside conventional closure.Exploration for deep basin-type accumulations should focus on depositional-structural-diagenetic sweet spots (DSDS), irrespective of conventional closure. This is of particular significance for a potential Nappamerri Trough deep basin accumulation because depositional models suggest that the best net/gross may be in structural lows, inherited from syndepositional lows, that host stacked channel sands within channel belt systems. Limiting exploration to conventionally-trapped gas may preclude intersection with such sweet spots.
DEEPWATER EXPLORATION: NORTH WESTERN AUSTRALIA COMPARED WITH GULF OF MEXICO AND MAURITANIA
Authors: Bussell M.R. , Jablonski D. , Enman T. , Wilson M.J. , Bint A.N.
Published: August 2017

Some of Australia’s deepwater frontiers are opening up for exploration, with existing and new companies taking acreage positions. Despite favourable fiscal terms and political stability, interest levels have not matched those in international hot spots due to key differences in perceived prospectivity.In this paper, Australia’s deepwater plays in the Northern Carnarvon Basin are compared and contrasted with deepwater plays in the Gulf of Mexico and offshore Mauritania. This comparison is largely based on Woodside Energy Ltd’s exploration pursuits in these areas.The Northern Carnarvon Basin deepwater plays are principally an extension of shallower water petroleum fairways, submerged to greater water depths by the absence of the Tertiary progradational, carbonate shelf sequence. Trap types and reservoir-seal pairs in the deepwater prospects are similar to their shallow water counterparts, but extensive deepwater areas carry an increased exploration risk due to the absence of this shelf overburden to load the Jurassic source rocks into the oil expulsion window. Hydrocarbons generated typically comprise dry gas from deeper Triassic source rocks, often trapped in sub-commercial quantities. Although the basin lacks a world class, widespread, oil-generating source rock, recent deepwater commercial oil discoveries in the Exmouth Sub-basin indicate the existence of a localised sweet spot associated with a Late Jurassic depocentre, similar to the proven Barrow-Dampier Subbasins located in shallower waters.In contrast, Woodside’s deepwater Gulf of Mexico and offshore Mauritania plays combine deepwater depositional systems with present day deepwater. They have reservoir-quality turbidite sandstones, well imaged on excellent quality 3D seismic, sealed by deep marine shales and charged by world class, organic-rich, prolific source rocks. Salt tectonics, shale diapirism and sloperelated slumping and thrusting have generated appealing structural styles, resulting in multiple play types and a density of prospects and leads not seen in Australia’s deepwater frontiers to date.Although elements of these plays are present at some locations in Australia’s deepwater, nowhere yet have all the required exploration ingredients for a major oil province been found juxtaposed as in the proven Gulf of Mexico and the highly prospective offshore Mauritania. Political stability and relatively favourable fiscal terms remain essential in attracting the exploration investment dollar to Australia’s deepwater.
THE TUBRIDGI GAS FIELD REJUVENATED
Authors: Bunt R.J.W. , Powell W.D. , Scholefield T.
Published: August 2017

Difficulties in defining the structural character of the reservoir horizons at the Tubridgi Gas Field arise from gas charging of thin, often laterally discontinuous, silts and sands within the overburden. The gas charging of these shallow, low permeability units results in a seismic representation of the field as a time low. Historically, conversion from time to a reliable depth image has been problematic due to the variable nature of the gas charging, the relatively sparse, multi-vintage 2D seismic coverage and the corresponding difficulties in defining an accurate velocity field.After the unsuccessful drilling program in 1997 when three out of the five wells were plugged and abandoned, a revised interpretation methodology was developed, incorporating all available geophysical data, but placing a much greater emphasis on geological information from each of the wells in the area.The new depth map and geological model were tested by the drilling of Tubridgi–16 to –18 in August 1999. These three wells intersected the Birdrong Sandstone within one metre of prognosis, with two wells located structurally up-dip of the previous 17 wells drilled on the field. This accuracy resulted in a 97% increase in remaining reserves and a much higher level of confidence in the structural configuration of the Tubridgi field.A core of the Lower Gearle Sandstone in the Tubridgi 18 well highlighted the potential of this zone which has subsequently been evaluated in greater detail and potentially represents an additional productive horizon for the field.
THE USE AND ABUSE OF FLUORESCENCE COLOURS AS MATURITY INDICATORS OF OIL IN INCLUSIONS FROM AUSTRALASIAN PETROLEUM SYSTEMS
Authors: George S.C. , Ruble T.E. , Dutkiewicz A.
Published: August 2017

It is well established that the fluorescence colours of crude oils shift towards the blue end of the spectrum with increased API gravity and implied thermal maturity. Oil inclusions also fluoresce, and it would be useful to correlate these fluorescence colours likewise to thermal maturity, because oil inclusions often contain the only direct evidence of residual oils once present in a reservoir. In order to validate this concept, the geochemical and petrographic properties of fluid inclusion oils in 36 sandstone samples from Australasian oil fields have been compared. A maturity assessment was made for each fluid inclusion oil using 25 molecular maturity ratios. Each fluid inclusion oil was placed in one of four maturity brackets, approximately equivalent to early, mid, peak and post oil generation windows.Samples containing mainly blue-fluorescing oil inclusions have thermal maturities throughout the oil window, including relatively low maturities (Rc
APPLICATIONS OF AROMATIC HYDROCARBONS: THE LIQUID REACTION ENVIRONMENT IN SOURCE ROCKS—A FUNDAMENTAL STAGE IN OIL FORMATION
Authors: Aarssen B.G.K. van , Alexander R. , Kagi R.I.
Published: August 2017

The ratio of two trimethylnaphthalenes in sediment extracts can be used to indicate the establishment of a liquid reaction environment in the source rock. The abundance of 1,3,6-TMN relative to 1,3,7-TMN (denoted here as 136/137) is near constant in crude oils. In sediments however, there is a much larger variation. This difference is attributed to the presence of two different reaction environments in the source rock: a liquid organic phase which is the direct precursor of crude oils, and the kerogen / rock matrix onto which compounds are adsorbed. In the liquid reaction environment, methylated naphthalenes undergo many reactions, leading to a near constant value for 136/137. On the other hand, when they are adsorbed onto kerogen or minerals, different reactions prevail and an excess of 1,3,6-TMN is formed. When measured in sediment extracts, the closer 136/137 is to the value typical for oils, the better the liquid reaction environments established in the source rock. This concept was used to study the behaviour of 136/ 137 with depth in 10 sedimentary sequences from the North West Shelf. The results showed that sediments from several wells were capable of establishing a liquid reaction environment, a necessary step in the formation of oil. Results from other wells indicated that little or no liquid reaction environment could be established, suggesting that these sediments were unlikely to be capable of oil formation. The 136/137 parameter is a convenient indicator for determining the extent to which the liquid reaction environment has been established in the source rock and may be useful in determining oil generation potential.
GEOLOGICAL CONTROLS ON OVERPRESSURE IN THE NORTHERN CARNARVON BASIN
Authors: Tingate P.R. , Khaksar A. , Ruth P. van , Dewhurst D. , Raven M. , Young H. , Hillis R. , Dodds K.
Published: August 2017

A small, but significant fraction of wells drilled in the Northern Carnarvon Basin have encountered problems with overpressure: better pore pressure prediction would improve safety and economy for drilling operations. In the Northern Carnarvon Basin the occurrence of overpressure and likely mechanisms are under investigation as part of the Australian Petroleum Cooperative Research Centre (APCRC) Research Program on Pore Pressure Prediction. Previous workers have proposed a number of mechanisms as the main cause of overpressure including undercompaction, hydrocarbon generation, horizontal stress and clay reactions.A preliminary regional study was undertaken incorporating over 400 well completion reports which identified approximately 60 wells with mud weights greater than 1.25 S.G. A subset of these wells was investigated and more reliable but much scarcer pressure indicators such as kicks or direct pressure measurements were examined. Depth-pressure profiles of wells across the region are variable and commonly show pressure compartmentalisation. Using a range of indicators, it was observed that overpressured strata in the Barrow Subbasin:occur over a wide depth range (2,500 to 4,000+ mbsl);occur over a wide stratigraphic range (Late Triassic to Late Cretaceous);are not regionally limited by major structural boundaries;are associated with sequences dominated by finegrained sediments with variable clay mineralogy; and in depositionally, or structurally, isolated sandstones; andmainly to the west of the Barrow and Dampier Subbasins around the Alpha Arch and Rankin Trend, coinciding with thickest Tertiary deposition.Previous published work in the study area has tended to support hydrocarbon generation as the primary cause of overpressure, though more recent publications have emphasised compaction disequilibrium. The log response (DT, RHOB and NPHI) of overpressured clay-rich strata has been investigated to constrain the type of overpressure mechanism. A normal compaction trend has been derived for four stratigraphic groupings; Muderong Shale, Barrow Group, Jurassic and Triassic. All overpressure occurrences were accompanied by an increase in sonic transit time. Not all wells have suitable log data for evaluation, but all stratigraphic groups show some evidence of elevated porosity associated with overpressure consistent with disequillibrium compaction as a dominant mechanism. Overpressures in the Barrow Group in Minden-1 and the Jurassic section within Zeepaard–1 do not have accompanying porosity anomalies suggesting a different overpressure mechanism model is needed.
DRILL BIT SEISMIC—DRILLING OPTIMISATION CASE STUDY: CRUX–1
Authors: Cao H. , Kurata Y.
Published: August 2017

Drill Bit Seismic (DBSeis) technique utilises the acoustic energy generated during the drilling process to provide vital information about the subsurface structure. This information, produced in real time at the wellsite, is used to optimise the drilling process, leading to significant cost savings and enhanced safety.When a working drill bit destroys the rock at the bottom of the hole, it radiates acoustic energy into the surrounding formation. This acoustic energy is recorded by sensors both at the top of the drill-string and placed on the sea floor in the vicinity of the rig. Travel times recorded by the sensors on the ground are corrected for drill-string travel times to provide the time-depth information. This accurate time-depth information can then be used to continuously update the depth of drilling hazards by converting the surface seismic markers from time into depth domain.After experiencing excessive loss of circulation in the Johnson Formation in a nearby well, DBSeis was run in the Crux–1 well to help predict the depth of the top Johnson Formation while drilling to the 13 3/8” casing shoe depth. The well program called for the casing shoe to be set as close to, but above this formation. The two way time of the Johnson formation had been estimated from the surface seismic to be 0.994 s. DBSeis was used to provide real time time-depth information to convert the two way time to depth.The estimated top Johnson Formation at 0.994 s two way time (TWT) corresponded to a depth of 1,231 m SS using pre-drill velocity information. Using the DBSeis time-depth data, this depth was reduced to 1,192 m SS and the casing shoe was set at 1,164 m SS. The actual depth of the top Johnson Formation was later estimated at 1,178 m SS from ROP/WOB.
FLNG—A NEW DAWN FOR LNG
Authors: Grasso W.H.
Published: August 2017

Shell has developed a new approach to the commercialisation of remote offshore natural gas assets. Floating LNG (FLNG) has the potential to change the face of LNG production and supply in the future and offer customers the opportunity to access an even wider scope of natural gas resources in the 21st Century.FLNG combines two simple, proven and reliable technologies: Floating Production, Storage and Offloading systems (FPSO) which are widely used in the oil industry, and LNG manufacturing, logistics and transportation. This paper describes progress by Shell, together with its Alliance partner Woodside, in applying its FLNG technology in northern Australia.The FLNG concept offers significant reductions in development costs across the supply chain, removing the need for offshore trunklines and combining platform and processing together with LNG production, storage and loading. FLNG also offers attractive opportunities for production of smaller tranches of LNG at a cost that can be competitive with brownfield expansion of onshore facilities.On the technical side, there has been practical field experience with almost all of the individual elements of an FLNG facility. Furthermore, Shell has carried out extensive engineering and design work on the integration of these elements to ensure that FLNG offers customers the same safety and reliability as from an onshore plant.With the combined advantages of market proximity, proven reliability, strong relationships with established and emerging customers, a politically stable environment and strong government support, Australia offers an exciting opportunity for the development and first deployment of FLNG.
HOW COMPETITIVE IS THE AUSTRALIAN INCOME TAX REGIME FOR EXPLORATION AND PRODUCTION?
Authors: Purdy B.
Published: August 2017

‘Australia must have a taxation system which equips it for the coming decades, not for those that have passed. If we do not achieve this, Australians will not enjoy the standard of living this nation has the potential to deliver’ (Ralph et al, 1999).One of the outcomes of the increasingly global nature of the resource industry is countries, especially those in close proximity to each other, are now competing for investment in resource projects. A key factor for investors assessing competing resource projects is the host country’s fiscal regime, including income tax, as this can significantly affect a project’s profitability and cash flow.The purpose of this paper is to give an overview of the income tax regime and issues currently facing the upstream Australian oil and gas industry (Sarich, 20001 ). In particular, this paper will:examine the Federal Government’s Review of Business Taxation and identify how the announcements impact on exploration and production activities;compare the Australian income tax regime on exploration and production to other countries in the region with whom Australia competes for investment and capital; andcomment on income tax issues facing Australian resource companies when conducting foreign activities.
NATIVE TITLE AND ABORIGINAL HERITAGE ISSUES AFFECTING OIL AND GAS EXPLORATION AND PRODUCTION
Authors: Hunt M.W.
Published: August 2017

This paper is principally concerned with native title issues as they affect oil and gas exploration and production. However, it also reviews Aboriginal heritage laws and practices because they have the potential to be just as disruptive to an expeditious exploration program or to the construction of a production facility as do native title claims.The paper focusses on onshore petroleum exploration and production because the right to negotiate under the Native Title Act (NTA) does not apply offshore. However, the paper does consider offshore because the NTA can still affect offshore petroleum explorers and producers; either because their area of interest could include an island within a State or Territory jurisdiction or because the facilities to treat the offshore oil and gas could be located onshore.The paper examines the key provisions of the NTA which are relevant to petroleum explorers and producers, principally the subject of tenure to ground. It considers the validity of already granted titles. It then examines the process of application for new titles.Although the NTA is the common source of problems throughout Australia, it is necessary for the paper to consider the situation in each State and Territory, since the titles are different and the government processes of dealing with native title issues differs in each jurisdiction.Although the focus of the paper is on how to cope with the right to negotiate, the paper considers some of the categories of future acts in respect of which the right to negotiate does not apply (specifically, procedures for infrastructure titles, renewals and extensions of titles, the expedited procedure, indigenous land use agreements, reserve land and approved exploration etc acts).The paper mentions the Federal Court decisions in the Miriuwung Gajerrong and Croker Island native title claims and ponders the options for the High Court in deciding the recent appeals.The paper’s conclusion is that a negotiated agreement is the only way to cope with native title issues. The contents of such an agreement are considered.
TOWARDS AN EFFICIENT EXPLORATION FRONTIER: CONSTRUCTING A PORTFOLIO OF STRATIGRAPHIC TRAPS IN FLUVIAL-LACUSTRINE SUCCESSIONS, COOPER-EROMANGA BASIN
Authors: Nakanishi T. , Lang S.C.
Published: August 2017

In the Cooper-Eromanga Basin, the future of exploration lies in identifying an appropriate exploration portfolio consisting of stratigraphic traps in structurally low or flank areas. A variety of stratigraphic trap prospects in the Moorari and Pondrinie 3D seismic survey areas are identified in the Patchawarra, Epsilon, Toolachee and Poolowanna formations. To identify the stratigraphic traps, an integration of sequence stratigraphic concepts applied to non-marine basins and advanced 3D seismic data visualisation was employed. This paper focusses on estimating the chance of geologic success and the probabilistic reserves size for each prospect within its sequence stratigraphic context (lowstand, transgressive or highstand systems tracts). The geologic chance factors for an effective stratigraphic trap include reservoir, top seal, lateral seal and bottom seal within each depositional systems tract, the seal effectiveness of the adjacent depositional systems tracts and the appropriate spatial arrangement of these factors. The confidence values for the existence of geologic chance factors were estimated according to the distributions of the possible reservoir and seal rocks within each genetic-stratigraphic interval and the chance of geologic success of each prospect was calculated. For probabilistic reserves estimation, geologically reasonable ranges were estimated for each parameter employing Monte Carlo simulation to calculate the reserves distribution. When a series of possible exploration portfolios, including single or multiple prospects from the prospect inventory are plotted in terms of the chance of geologic success vs. the mean value of the reserves estimate, an efficient exploration frontier emerges. The portfolio candidates on the efficient exploration frontier were assessed with regard to chance of economic success and expected net present value (ENPV) using a simple cash flow model. The results indicate that appropriate portfolios include multiple prospect exploration especially with lowstand systems tract plays using single or multiple exploration wells. The portfolio construction approach for stratigraphic trap exploration should ultimately be made consistent with conventional play types, to enable an assessment of all exploration opportunities.
MICROSTRUCTURAL AND GEOMECHANICAL CHARACTERISATION OF FAULT ROCKS FROM THE CARNARVON AND OTWAY BASINS
Authors: Dewhurst D.N. , Jones R.M. , Hillis R.R. , Mildren S.D.
Published: August 2017

The results of natural and laboratory-induced fault behaviour from wells in the Otway Basin are compared with sample material from a producing Carnarvon Basin field where rocks from a fault zone have been cored. Capillary pressure, microstructural and juxtaposition data obtained from these fault rocks indicate a capability to hold back gas columns in excess of 100 m, yet many fault closures are found to contain only palaeo-columns. Trap failure is usually attributed to reactivation of trap-bounding faults, often during Miocene-Recent times in these basins. Faults susceptible to reactivation can be predicted by geomechanical methods involving the determination of the in-situ stress field and the orientation and dip of faults with respect to that stress field. Failure envelopes of fault rocks have been determined to estimate reactivation potential in the present day in-situ stress field. This approach works well where fault rocks are weaker than the host reservoir sandstone, but may not be applicable where fault rocks are stronger. In fields where the latter is the case, intact hydrocarbon columns are present, irrespective of whether faults are optimally oriented for reactivation. This indicates that the assumptions of zero cohesive strength and constant friction coefficient for predicting the reactivation potential of fault rocks may not be completely reliable.
CALIBRATING PREDICTIONS OF FAULT SEAL REACTIVATION IN THE TIMOR SEA
Authors: Mildren S.D. , Hillis R.R. , J.Kaldi
Published: August 2017

Predictions of the likelihood of fault reactivation for five fault-bound prospects in the Timor Sea are made using the FAST (Fault Analysis Seal Technology) technique. Fault reactivation is believed to be the dominant cause of seal breach in the area. Calculations are made using a stress tensor appropriate for the area, a conservative fault-rock failure envelope and the structural geometries of each prospect. A depth-stress power relationship defines the vertical stress magnitude based on vertical stress profiles for 17 Timor Sea wells.Empirical evidence of hydrocarbon leakage at each trap is used to investigate the accuracy of the fault reactivation-based predictions of seal integrity. There is a good correlation between evidence of leakage and the risk of reactivation predicted using the FAST technique. Risk of reactivation is expressed as the pore pressure increase (ΔP) that would be required to induce failure. This study allows the fault reactivation predictions to be calibrated in terms of risk of seal breach. Low integrity traps are associated with ΔP values less than 10 MPa, moderate integrity traps correspond with values between 10 and 15 MPa and high integrity traps correspond with values greater than 15 MPa. Faults with dip magnitudes greater than 60° in the Timor Sea area are likely to have a high risk of reactivation and shear failure is the most likely mode of reactivation.
SEAL POTENTIAL IN CRETACEOUS AND LATE JURASSIC ROCKS OF THE VULCAN SUB-BASIN, NORTH WEST SHELF AUSTRALIA
Authors: Kivior T. , Kaldi J.G. , Lang S.C.
Published: August 2017

The occurrence of palaeo-oil columns in Late Jurassic and Cretaceous reservoirs in the Vulcan Sub-basin suggests that hydrocarbon accumulations have leaked. It is unclear whether accumulations have leaked through breach of top seal or fault seal. This paper evaluates the top seal potential for hydrocarbon accumulations in the Vulcan Sub-basin. Seal potential (SP) combines seal capacity (the hydrocarbon column height that can physically be held back by a seal), seal geometry (the areal extent and thickness of the seal) and seal integrity (rock mechanical properties of the seal). Seal capacities are measured using mercury injection capillary pressure calculations. Areal extent is evaluated using sedimentological and sequence stratigraphic principles. Thickness is determined empirically from well logs and seismic data. Seal integrity is derived from a brittleness index. In addition, a component relating to data quality and quantity is included in seal potential evaluation.Lower Vulcan Formation SP ranges from low to high due to variations in seal capacity and thickness risks as well as data quality and quantity. High SP occurs in the main depocentres and low SP occurs on palaeo-highs and basin margins. Upper Vulcan Formation SP ranges from low to moderate due to variations in seal capacity and data issues. Moderate SP occurs in depocentres and low SP on basin margins. In the Echuca Shoals Formation seal capacity, seal extent and integrity as well as data quality and quantity are good. Seal thickness, however, is inconsistent, resulting in SP variations from good to poor as a function of thickness. Jamieson Formation has high seal capacities, is thick and areally extensive. The seal potential, however, is locally moderate (e.g. on the Ashmore Platform) due to integrity issues. Woolaston, Gibson and Fenelon (WGF) Formations are grouped together as the regional seal and in this group SP varies from low to high. The WGF rocks have high seal capacities, are areally extensive and thick and the data quality and quantity is good. The main risk is integrity, which increases from northwest to southeast in the basin.Based on the overall seal potential analyses, almost all seals in the area are capable of holding back hydrocarbon columns greater than present or paleocolumns encountered. This suggests that hydrocarbon leakage in the Vulcan Sub-basin was unlikely to have occurred as a result of top seal capillary failure.
INFLUENCE OF HYDROCARBON MIGRATION AND SEEPAGE ON BENTHIC COMMUNITIES IN THE TIMOR SEA, AUSTRALIA
Authors: O’Brien G.W. , Glenn K. , Lawrence G. , Williams A.K. , Webster M. , Burns S. , Cowley R.
Published: August 2017

The Ashmore Platform–Timor Sea region of Australia’s North West Shelf is an area of significant petroleum exploration potential, with several large commercial oil fields present. Moreover, exploration activity seems likely to continue at current levels for the foreseeable future, and may also extend into deeper water, given high oil prices and improved drilling technologies. The area is also one of high conservation value, with both the Cartier Marine reserve and Ashmore Reef (a Category 1 marine park), as well as numerous other genetically-rich carbonate seed bank systems, closely associated spatially with exploration activities. Balancing the conservation and resource values in this area will present a key challenge into the future.The magnitude of this challenge has been highlighted by recent work undertaken by AGSO, which involved the acquisition and interpretation of assorted remote sensing data, such as high-resolution bathymetry (including sidescan sonar), satellite synthetic aperture radar (SAR), Landsat, water column geochemical sniffer, airborne laser fluorosensor, seismic data and seafloor sediment sampling. These studies have shown that, at both a regional and local scale, the development of these important carbonate systems appears to directly relate to the geological development of the area.At a regional scale, the collision between the Australian and Eurasian crustal plates in the Pliocene (At a local scale, new data also strongly suggest that the locations of the majority of reefs and carbonate banks and build-ups in the area are associated with active and palaeo-hydrocarbon seeps. These seeps are localised over either fault systems which tap the reservoir, along migration fairways, or at the pinch-out of the regional Cretaceous top seal. Our interpretations suggest that the reefs and the build-ups formed by a sequential process. Firstly, hydrocarbon seepage (induced by collisionrelated faulting) localised small seafloor (chemolithotrophic) biological carbonate communities, which ultimately formed topographically positive features. These higher relief features were subsequently preferentially colonised by an assortment of reef-building biota, whose rapid growth progressively kept up with rising sea-level (which was driven principally by collisionrelated subsidence). The most favourable conditions for initial reef colonisation probably occurred during periods of relatively low sea-level, when the areas around the reefs were located at much shallower water depths (Clearly, the fact that the genetically rich carbonate communities in this area are probably causally related to natural hydrocarbon seepage (and the attendant processes which drove that seepage) will present a series of almost unique exploration, development (especially engineering) and conservation challenges.
ACOUSTIC PROPERTIES OF MUDERONG SHALE
Authors: Dewhurst D.N. , Raven M.D. , Ruth P. van , Tingate P.R. , Siggins A.F.
Published: August 2017

The presence of smectitic shales often causes serious problems for drillers in the form of both overpressures due to low permeability and wellbore stability problems resulting from the presence of swelling clays. Prediction of overpressures in such sediments is hampered by interlayer water in the mineral structure that is not accounted for in porosity determinations whether by wireline methods or laboratory drying techniques. This study looks at the detailed physical properties and microstructure in relation to acoustic response of the Muderong Shale, a smectitic shale from the Carnarvon Basin on the Northwest Shelf of Australia. Porosity determined from acoustic or standard drying techniques is far in excess of that determined by both helium and mercury porosimetry, but correcting for interlayer water results in the values determined by the latter techniques. Physical properties are intimately tied to the acoustic response of the Muderong Shale at both sonic and ultrasonic frequencies. The presence of smectite results in anomalously low velocities in the Muderong Shale and the development of both compaction fabrics and induced microfracture generation result in significant acoustic anisotropy. Velocity variations from downhole shales in wells from the Carnarvon Basin can mainly be tied to smectite content but also to overpressure. The high degree of anisotropy of the Muderong Shale at ambient pressure can be related to the presence of both a sedimentary compaction fabric and high aspect ratio compliant microfractures. Determination of the relative contributions of these two causes of anisotropy in shales may provide a method by which to distinguish overpressure-generating mechanisms from acoustic data.
OLIGO-MIOCENE CANYONS IN THE GAMBIER SUB-BASIN, SOUTHERN AUSTRALIA—DEEPWATER ANALOGUES FOR PETROLEUM EXPLORATION
Authors: Pollock R.M. , Li Q. , McGowran B. , Lang S.C.
Published: August 2017

The Gambier Sub-basin lies on the southern Australian passive continental margin that formed during continental breakup and seafloor spreading between the Australian and Antarctic plates. In addition to the numerous modern submarine canyons reported on the southern Australian margin, three palaeo-canyon systems have been identified within the Gambier Limestone of the South Australian Gambier Sub-basin. Favourable environmental conditions during the Oligocene and Early Miocene led to deposition of the Gambier Limestone, a widespread, prograding extra-tropical carbonate platform. A world-wide glacio-eustatic sea level fall in the Early Oligocene exposed the shelf in the Gambier Subbasin, causing widespread erosion and minor fluvial incision on the shelf and subsequent formation of nick points at the shelf edge. During the following marine transgression later in the Oligocene, the shelf was inundated and the nick points provided conduits for erosive turbidity currents to enlarge the canyons to the spectacular dimensions observed on seismic data. No less than 20 successive canyon cut and fill events ranging from Late Oligocene to Middle Miocene have been observed and mapped on seismic data across the shelf in the Gambier Sub-basin. The thick, dominantly fine-grained carbonate sheet logically represents a potential regional seal to underlying clastic reservoirs. However, the possibility exists for carbonate reservoir sands to be present within the palaeo-canyons, sealed by surrounding fine-grained carbonates. Although no hydrocarbons have yet been identified in the carbonates of the Gambier Sub-basin, the canyons provide an analogue useful for establishing the scale, internal architecture and geometry of canyon fill systems.
EVALUATION OF HYDROCARBON SEEPAGE IN THE GREAT AUSTRALIAN BIGHT
Authors: Struckmeyer H.I.M. , Williams A.K. , Cowley R. , Totterdell J.M. , Lawrence G. , O’Brien G.W.
Published: August 2017

The regional assessment of hydrocarbon seepage is built around a combination of Radarsat and ERS Synthetic Aperture Radar (SAR) data, acquired during 1998 and 1999, as part of a collaborative project between Geoscience Australia, Nigel Press Associates, Radarsat International and AUSLIG (specifically the Australian Centre for Remote Sensing). In total, 55 Radarsat Wide 1 Beam Mode scenes and one ERS scene from the Great Australian Bight (GAB) region were analysed. The data were integrated with regional geological information, and other hydrocarbon migration and seepage indicators such as reprocessed and reinterpreted legacy Airborne Laser Fluorosensor (ALF) data, to provide an assessment of the possible charge characteristics of the region.The results of the study suggest that active, though areally restricted, liquid hydrocarbon seepage is occurring within the Bight Basin. The majority of seepage slicks occur along the outer margin of the major depocentre, the Ceduna Sub-basin, in areas where significant Late Tertiary to Recent faulting extends to the seafloor. Very little evidence of seepage was observed on the SAR data above the main depocentre, which is an area of minimal Late Tertiary to Recent faulting. Reprocessed ALF data reveal three main areas with relatively dense fluors. Although they are not directly coincident with locations of seepage interpreted from SAR data, their distribution support the pattern of preferred leakage along the basin margins.Integration of regional geological models with the results of this study suggests that structural features related to active tectonism have focused laterally migrating hydrocarbons to produce active seepage at specific locations in the basin. Where these features are absent, seepage may be passive and/or be governed by long distance migration to points of seal failure. Together with oil and gas shows in exploration wells, observations from this study provide further evidence that liquid hydrocarbons have been generated in the Great Australian Bight.
MACROCYCLIC ALKANES: MARKERS FOR THE FRESHWATER ALGA BOTRYOCOCCUS BRAUNII IN THE GIPPSLAND BASIN
Authors: Audino M. , Grice K. , Alexander R. , Kagi R.I.
Published: August 2017

Macrocyclic alkanes are novel markers derived from the algaenan of Botryococcus braunii (B. braunii) independent of the race of B. braunii. Analysis of a crude oil (Leatherjacket–1, Cretaceous) and a sediment from the Gippsland Basin (Flounder–1 well, Cretaceous) reveal the presence of macrocyclic alkanes, suggesting an input to the organic matter from freshwater alga B. braunii. This is the first report of macrocyclic alkanes in Australian crude oils and in sediments other than torbanites. These compounds are important because they ultimately derive from the algaenan of B. braunii and are thus selectively preserved in crude oils unlike other B. braunii biomarkers that are not always preserved.
AN INTEGRATED PETROPHYSICAL WORKFLOW TO GENERATING FLUID SUBSTITUTED LOGS FOR AVO CHARACTERISATION—GIPSY AND NORTH GIPSY FIELDS CASE STUDY, NORTH WEST SHELF, AUSTRALIA
Authors: Clarke D.L , Clare A.P
Published: August 2017

As part of a multi-well field study an integrated petrophysical workflow was developed to include the generation of fluid substituted logs for AVO characterisation.The workflow relied upon the construction of a multimineral model that best approximated the actual mineral content of the reservoir. Any limitations or assumptions were noted and taken into account when creating the multi-mineral model. Other petrophysical results were derived from the same model to validate its consistency such as intrinsic permeability, porosity, water saturation, etc. Iteration between the model and the results was required until a consistent model was achieved.The estimation of an intrinsic permeability log was based upon the k-Lambda method that uses the multimineral model and porosities.The estimation of a shear slowness log and the fluid substituted logs was based upon elastic rock properties derived from the multi-mineral model and the acquired compressional slowness log and bulk density log. This integrated approach provides a higher confidence in the derived results, which are then used as input into the reservoir model, thereby improving the reserve calculations.The interdependence of each derived result on the same input multi-mineral model ensures consistency and predictability in a complex geological environment, which captures all available information.The method is demonstrated with the Gipsy–1 and North Gipsy–1 wells, which were part of the original field study.
HIGH RESOLUTION SEQUENCE STRATIGRAPHY, RESERVOIR ANALOGUES, AND 3D SEISMIC INTERPRETATION—APPLICATION TO EXPLORATION AND RESERVOIR DEVELOPMENT IN THE BARYULAH COMPLEX, COOPER BASIN, SOUTHWEST QUEENSLAND
Authors: Lang S.C. , Ceglar N. , Forder S. , Spencer G. , Kassan J.
Published: August 2017

Gas exploration and reservoir development in the Baryulah area, Cooper Basin, southwest Queensland has focussed on the fluvial-lacustrine, Permian coal-bearing Patchawarra Formation, Murteree Shale, Epsilon and Toolachee Formations. Geological interpretation of drilling and 3D seismic data has benefitted from integration of sequence stratigraphic concepts with the judicious use of reservoir analogues and seismic attribute mapping. Initially, a coherent regional chronostratigraphic framework was established, based on broad palynological zonations, and correlating extensive lacustrine flooding surfaces and unconformities, tied to 3D seismic reflectors. This framework was subdivided by using local key surfaces identified on wireline logs (usually high-gamma shaly intervals overlying coals), resulting in recognition of numerous high-resolution genetic units. Wireline log character, calibrated by cores from analogous fields around the Cooper Basin and supported by analogue studies, forms the basis for a logfacies scheme that recognises meandering fluvial channels, crevasse splays, floodplain/basin, and peat swamps/mires. Fluvial stacking patterns (aggradational, retrogradational or progradational), produced by the ratio of sediment supply to accommodation within each genetic unit, were used to help determine depositional systems tracts (alluvial lowstand, transgressive, or highstand) and likely reservoir connectivity. Log signature maps for genetic intervals form the basis of palaeogeographic mapping. Modern and ancient depositional analogues were used to constrain likely facies distribution and fluvial channel belt widths. Syndepositional structural features, net-to-gross trends, and seismic attribute mapping are used to guide the scale, distribution and orientation of potential reservoir trends. When used in conjunction with structural and production data, the palaeogeographic maps help develop stratigraphic trap play concepts, providing a predictive tool for locating exploration or appraisal drilling opportunities.