Journal articles on the topic 'Otway Basin (Vic and S A )'

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

An extensive volume of 3D seismic data over a number of oil and gas fields in Australia's North West Shelf and Gippsland Basin has been examined for evidence of the effects of hydrocarbon migration and/or leakage. For comparative purposes, 2D and 3D data have also been studied over a number of adjacent traps, including dry traps and partially to completely breached accumulations. Fields and traps investigated include Bayu-Undan, Jabiru, Skua, Swift and Tahbilk in the Bonaparte Basin, Cornea in the Browse Basin, North Rankin, Chinook, Macedon, Enfield and Zeewulf in the Carnarvon Basin, and Kingfish in the Gippsland Basin. The principal goal of the study is to provide representative case studies from known fields so that, in undrilled regions, the exploration uncertainties associated with the issues of hydrocarbon charge and trap integrity might be reduced.Direct indicators of hydrocarbon migration and/or leakage are relatively rare throughout the basins studied, though the discoveries themselves characteristically show seismic anomalies attributable to hydrocarbon leakage. The nature and intensity of these hydrocarbon-related seismic effects do, however, vary dramatically between the fields. Over traps such as Skua, Swift, Tahbilk and Macedon, they are intense, whereas over others, for example Chinook and North Rankin, they are quite subtle. Hydrocarbon-related diagenetic zones (HRDZs), which had been identified previously above the reservoir zones of leaky traps within the Bonaparte Basin, have also been recognised within the Browse, Carnarvon, Otway and Gippsland Basins. HRDZs are the most common leakage indicators found and are identified easily via a combination of high seismic amplitudes through the affected zone, time pull-up and degraded stack response of underlying reflectors. In some cases (the Skua and Macedon Fields), the HRDZs actually define the extent of the accumulations at depth.Anomalous, subtle to strong, seismic amplitude anomalies are associated with the majority of the major fields within the Carnarvon Basin. The strength and location of the anomalies are related to a complex interplay between trap type (in particular four-way dip-closed versus fault dependent), top seal capacity, fault seal integrity, and charge history. In some areas within the Carnarvon, Browse and Bonaparte Basins, shallow amplitude anomalies can be related directly to gas chimneys emanating from the reservoir zone itself. In other instances, the continuous migration of gas from the reservoir has produced an assortment of pockmarks, mounds and amplitude anomalies on the present day sea floor, which all provide evidence of hydrocarbon seepage. In the Browse Basin, strong evidence has been found that many of the modern carbonate banks and reefs in the region were initially located over hydrocarbon seeps on the palaeo-seafloor.The examples and processes presented demonstrate that the analysis of hydrocarbon leakage indicators on seismic data can help to better understand exploration risk and locate subtle hydrocarbon accumulations. In mature exploration provinces, this methodology may lead to the identification of subtle accumulations previously left undetected by more conventional methods. In frontier regions, it can help to identify the presence of a viable petroleum system, typically the principal exploration uncertainty in undrilled regions.

Recent exploration by BHP Petroleum in VIC/ P30 and VIC/P31, within the eastern Otway Basin, has contributed significantly to our understanding of the depositional history of the Paleocene to Eocene siliciclastic Wangerrip Group. The original lithostratigraphic definition of this group was based on outcrop description and subsequently applied to onshore and, more recently, offshore wells significantly basinward of the type sections. This resulted in confusing individual well lithostratigraphies which hampered traditional methods of subsurface correlation.A re-evaluation of the Wangerrip Group stratigraphy is presented based on the integration of outcrop, wireline well log, palynological and reflection seismic data. The Wangerrip Group can be divided into two distinct units based on seismic and well log character. A lower Paleocene succession rests conformably on the underlying Maastrichtian and older Sherbrook Group, and is separated from an overlying Late Paleocene to Eocene succession by a significant regional unconformity. This upper unit displays a highly progradational seismic character and is named here as the Wangerrip Megasequence.Regional seismic and well log correlation diagrams are used to illustrate a subdivision of the Wangerrip Megasequence into eight third-order sequences. This sequence stratigraphic subdivision of the Wangerrip Group is then used to construct a chronostratigraphic chart for the succession within this part of the Otway Basin.

The Thylacine and Geographe gas fields were discovered in mid-2001 in the offshore Otway Basin, in permits T/30P and VIC/P43 respectively. Geographe is 55 km south of Port Campbell and Thylacine is a further 15 km offshore, in the depo-centre of the Shipwreck Trough, in water depths of 80 m to 100 m. The Thylacine–1 well intersected a 277 m gas column in Turonian to Santonian aged reservoirs. Geographe–1 intersected a 233 m gas column in a similar sedimentary section. Thylacine–2, 5.7 km west of Thylacine–1, confirmed the field extent, and flowed gas at 28 MMSCFD (0.79 Mm3/D). Critical to the discovery of these fields was the Investigator 3D seismic survey, which covered about 1,000 km2 of the central Shipwreck Trough. The pre-drill chance of success of both structures was high-graded as a result of excellent structural imaging and the conformance of amplitude and AVO anomalies to mapped closures. The interpretation of this survey and the subsequent drilling of the Thylacine and Geographe Fields have dramatically increased the understanding of the structure and stratigraphy of the offshore eastern Otway Basin particularly in relation to the Shipwreck Trough and the Sorell Fault Zone.Combined dry gas reserves at the proved and probable level stand at 0.85 TCF and condensate reserves at 10.7 MMBBL. The fields are undergoing integrated sub-surface, development and environmental studies with the aim of supplying the nearby southeastern Australian gas markets. The preferred development concept is a small jacket structure at Thylacine, followed by a subsea tie-in of the Geographe Field with onshore processing facilities near Port Campbell.

The hydrocarbons discovered to date on the southern margin of Australia have been assigned to the Austral Petroleum Supersystem based on the age of their source rocks and common tectonic history. Modelling of the source facies distribution within this supersystem using tectonic, climatic and geographic history of the southern margin basins, suggests the presence of a variety of source rocks deposited in saline playa lakes, fluvial, lacustrine, deltaic and anoxic marine environments.Testing of the palaeogeographic model using geochemical characteristics of liquid hydrocarbons confirms the three-fold subdivision (Al, A2 and A3) of the Austral Petroleum Supersystem.Bass Basin oils are assigned to the Austral 3, Eastern View Petroleum System. The presence of oleanane in the biomarker assemblages of these oils, together with their negatively sloping, heavy, isotopic profiles, indicate derivation from Upper Cretaceous-Tertiary fluvio–deltaic source facies.In the eastern Otway Basin, oils of the Austral 2, Eumeralla Petroleum System are sourced by Lower Cretaceous (Aptian–Albian) coaly facies. Oil shows reservoired in the Wigunda Formation at Greenly-1 in the Duntroon Basin are possibly sourced from the Borda Formation and are assigned to the Austral 2, Borda Petroleum System.In the western Otway, Duntroon and Bight basins, a lack of definitive oil-source rock correlations precludes the identification of individual Austral 1 petroleum systems.

Vast areas of Australia's continental margin sedimentary basins lying seawards of the 200 m water depth line, or shelf edge, are under-explored for petroleum. Indeed, most are essentially unexplored. However, recent advances in drilling and production technology, as well as recent reconnaissance seismic, geochemical, geothermal and seabed sampling data collected by the Bureau of Mineral Resources' (BMR) Marine Division, may reduce the perceived economic risk of many of these deepwater basins relative to their shelf counterparts. Triassic reefs have been identified off the northern Exmouth Plateau and possibly in the deepwater Canning Basin, locally within a predicted oil window. In the deepwater North Perth Basin, major wrench structures have been identified. The deepwater areas of the Great Australian Bight and Otway Basin are actually the main depocentres of a major basin complex lying along the almost totally unexplored southern Australian continental margin. The Latrobe Group in the outer Gippsland Basin is likely to have similar geology to the well explored and productive shelf basin, but remains untested. The Queensland and Townsville troughs, in deepwater off northeast Australia, contain many significant structures typical of unbreached rift systems.All these areas have been risked relative to each other and their prospectivity assessed. The most attractive frontier areas in terms of relative risk may be the Otway and North Perth basins. The highest potential may occur in the deepwater rift troughs off northeast Australia, although the relative risk is very high. Triassic reefs of the Northwest Shelf may have the best prospectivity in the shorter term, given that they are known from drilling in a region with proven source potential and a substantial exploration infrastructure.

A regional seismic interpretation ot the on shore Otway Basin has been completed and used to determine the basin's structural history.Sedimentation commenced in the Tithonian-Berriasian with the deposition of the volcanogenic Casterton Formation and continued into the Berriasian-Barremian with the deposition in elongate half graben, of thick fluviolacustrine sediments of the Crayfish Group, typically thickening dramatically towards the bounding faults. The NW to W trend of Crayfish Group depocentres and their major bounding faults suggest that the initial extension direction was N-S to NE-SW in the Late Jurassic-Early Cretaceous. Dextral transtensional movement occurred along the Trumpet Fault in the west of the basin and was complemented by sinistral transtension on the major NNE striking faults of the Torquay Sub-basin in the east during this period.The dip direction of the pre-Barremian bounding faults changes a number of times along the northern margin of the basin. These changes occur across transfer/accommodation zones of complex faulting and folding, not over discrete transfer faults.Faulting and related uplift resulted in partial erosion of the Crayfish Group from a number of structural highs, prior to the Aptian. The half graben faults are overlain by Eumeralla Formation indicating that active rifting had ceased by the Aptian in the onshore Otway Basin. Further erosion occurred following post-Albian faulting and uplift prior to the Paleocene, in particular within the eastern part of the basin.During deposition of the Sherbrook Group in the Late Cretaceous, fault reactivation produced minor, shallow grabens within the older half graben systems. Major movement also continued along the Tartwaup Fault Zone, resulting in basin deepening toward the SW. This fault activity continued into the Paleocene-Early Eocene during deposition of the Wangerrip Group. In the Eocene, the Southern Ocean spreading rates changed from slow to fast, resulting in the late-Early Eocene deltaic sediment of the Upper Wangerrip Group covering some of the earlier extension faults. Compression, resulting in right-lateral wrenching and inversion of previous faults, occurred during the Miocene-Recent. Pliocene-Holocene volcanic activity occurred along zones of weakness related to these fault systems.

Mesozoic extension along Australia's southern margin and the evolution and architecture of the Otway Basin were probably controlled by three factors: 1) changes in global plate movements driven by mantle processes; 2) the structural grain of Palaeozoic basement; and, 3) changes in subduction along Gondwana's Pacific margin. Major plate realignments controlled the Jurassic onset of rifting, the mid-Cretaceous break-up and the Eocene onset of rapid spreading in the Southern Ocean.The initial southern margin rift site was influenced by the northern limit of Pacific margin (extensional) Jurassic dolerites and the rifting may have terminated dolerite emplacement. Changed conditions of Pacific margin subduction (e.g. ridge subduction) in the Aptian may have placed the Australia-Antarctic plates into minor compression, abating Neocomian southern margin rifting. It also produced vast amounts of volcanolithic sediment from the Pacific margin arc that was funnelled down the rift graben, causing additional regional subsidence due to loading. Albian orogenic collapse of the Pacific margin, related to collision with the Phoenix Plate, influenced mid-Cretaceous breakup propagating south of Tasmania and into the Tasman Sea.Major offsets of the spreading axis during breakup, at the Tasman and Spencer Fracture zones, were most likely controlled by the location of Palaeozoic terrane boundaries. The Tasman Fracture System was reactivated during break-up, with considerable uplift and denudation of the Bass failed rift to the east, which controlled Otway Basin facies distribution. Palaeozoic structures also had a significant effect in determining the half graben orientations within a general N-S extensional regime during early Cretaceous rifting. The late Cretaceous second stage of rifting, seaward of the Tartwaup, Timboon and Sorell fault zones, left a stable failed rift margin to the north, but the attenuated lithosphere of the Otway-Sorell microplate to the south records repeated extension that led to continental separation and may be part of an Antarctic upper plate.

The water resources status and availability of any river basin is of primary importance for overall and sustainable development of any river basin. This study has been done in Beas river basin which is located in North Western Himalaya for assessing the status of water resources in present and future climate change scenarios. In this study hydrological modelling approach has been used for quantifying the water balance components of Beas river basin upto Pandoh. The variable infiltration capacity (VIC) model has been used in energy balance mode for Beas river basin at 1km grid scale. The VIC model has been run with snow elevation zones files to simulate the snow module of VIC. The model was run with National Centre for Environmental Prediction (NCEP) forcing data (Tmax, Tmin, Rainfall and wind speed at 0.5degree resolution) from 1 Jan. 1999 to 31 Dec 2006 for calibration purpose. The additional component of glacier melt was added into overall river runoff using semi-empirical approach utilizing air temperature and glacier type and extent data. The ground water component is computed from overall recharge of ground water by water balance approach. The overall water balance approach is validated with river discharge data provided by Bhakra Beas Management Board (BBMB) from 1994-2014. VIC routing module was used to assess pixel wise flow availability at daily, monthly and annual time scales. The mean monthly flow at Pandoh during study period varied from 19 - 1581 m³/s from VIC and 50 to 1556 m³/sec from observation data, with minimum water flow occurring in month of January and maximum flow in month of August with annual R² of 0.68. The future climate change data is taken from CORDEX database. The climate model of NOAA-GFDL-ESM2M for IPCC RCP scenario 4.5 and 8.5 were used for South Asia at 0.44 deg. grid from year 2006 to 2100. The climate forcing data for VIC model was prepared using daily maximum and minimum near surface air temperature, daily precipitation and daily surface wind speed. The GFDL model also gives validation phase scenarios from 2006 to 2015, which are used to test the overall model performance with current data. The current assessment made by hydrological water balance based approach has given reasonable good results in Beas river basin. The main limitation of this study is lack of full representation of glacier melt flow using fully energy balance model. This component will be addressed in coming time and it will be integrated with tradition hydrological and snowmelt runoff models. The other limitation of current study is dependence on NCEP or other reanalysis of climate forcing data for hydrological modelling, this leads to mismatch between actual and simulated water balance components. This problem can be addressed if more ground based and fine resolution grid based hydro meteorological data are used as input forcing data for hydrological modelling.

As part of the Victorian Gas Program, new geological modelling of the Cretaceous to recent deposits in the Port Campbell Embayment and the Mussel Platform was carried out to investigate fault seal and trap integrity. Structural characterisation of the Late Cretaceous to present-day sedimentary sequence highlights cross-cutting fault trends defining potential structural traps containing Waarre Formation reservoirs. The fault trends are primarily controlled by Cretaceous-Paleogene extension and are reactivated during the Paleogene. Seismic facies in the top seal suggest an N-S environmental shift from open-marine to proximal nearshore marine. The quantification of fault membrane seals suggests that while reservoir-on-reservoir juxtapositions may enable some degree of lateral flow, efficient trapping relying on juxtaposition seal against the Belfast or Skull Creek mudstones is widespread. Fault geomechanics suggests that NW-SE and E-W faults accommodated most of the extensional strain and could have been associated with increased vertical structural permeability; however, there are no leakage indicators to support widespread vertical migration. These results do not support previous assumptions that fault seal integrity and top seal bypass represent a critical and widespread issue within the nearshore Otway Basin.

The Halladale and Black Watch fields are adjacent fault-dependent gas accumulations at the Turonian Waarre Formation level situated in the eastern Otway Basin, about 4–5 km from shore in VIC/RL2(v). The two fields were first identified in 2002 when anomalous seismic amplitudes were observed on the tail-ends of several 90s-vintage 2D lines that extended into what was then vacant acreage. After being awarded the block as VIC/P37(v) Origin Energy Limited and its joint venture (JV) partner, Woodside Energy Limited, acquired a 211 km2 full-fold 3D seismic survey over the anomalous amplitudes in late 2003. Subsequent analysis of the seismic volume revealed two tilted fault blocks with strong amplitude variation with offset (AVO) anomalies in the Waarre A and Waarre C units that conformed to structure and appeared to shut off at the same depth. A similar AVO anomaly was also observed in the overlying Santonian Nullawarre Formation, raising the possibility that Halladale and/or Black Watch had leaked or were leaking. In early 2005, the VIC/P37(v) JV drilled two exploration wells targetting the key Waarre C reservoir on the eastern flank of Halladale and eastern crest of Black Watch. Both wells encountered live gas columns in the Waarre C but no GWCs were observed on logs and wireline pressure data indicated the two fields were not in pressure communication. A third well was then drilled down-dip of the Waarre C AVO shut off on the Halladale fault block to obtain a water gradient from the Waarre C. This well proved invaluable in determining the height of the gas columns in the Waarre C at both fields as it showed the gas-water contacts (GWCs) at Halladale (1,760 mSS) and Black Watch (1,770 mSS) were shallow to their respective AVO shut offs by about 20 m and 10 m respectively. Subsequent analysis of shear wave sonic data from the third well indicated there is a 17 m residual gas column at the base of the Halladale Field. This suggests Halladale either leaked slightly at some time in the past or is still leaking. A similar scenario may also occur at Black Watch. Given the close proximity of the two fields to the coast, development scenarios from onshore are now being considered.

Strike Oil was a very small unlisted Australian company with a capitalisation of less than A$10 million when it decided to bid for block V98-4 (now VIC/P44) in the offshore Otway Basin in early 1999.Block V98-4 met Strike Oil’s gas strategy of pursuing opportunities in basins close to infrastructure and markets in the eastern states of Australia.Prior to making the bid Strike Oil identified the geological, financial and operational risks associated with exploring the permit, especially with regard to conducting a 3D seismic survey in the environmentally sensitive and sometimes hostile Bass Strait. This led to the implementation of, and adherence to, a comprehensive risk management plan.The geological risks were addressed by acquiring 3D seismic and conducting an analysis of the amplitudes and AVO responses associated with nearby gas discoveries and dry holes.Management of the financial risk centred firstly around not overbidding and secondly finding a farmee who could add value to the permit during both the exploration and exploitation phases.The operational risks were all associated with conducting the Casino 3D seismic survey. Local environmental considerations, particularly in relation to migratory whale species and the seasonal activities of local fishermen, meant there was only a six weeks’ time window available for unhindered operations. This window also coincided with the spring gale season, when weather conditions can stop marine operations.The use of experienced personnel, early stakeholder consultation, and the use of contingency plans, enabled Strike Oil to achieve its objectives under adverse conditions. The Casino 3D seismic survey, despite the odds, was completed on time, under budget, and with less than 7% infill, while still delivering high quality data.The farmout, the acquisition and processing of the 3D seismic data, and the discovery and appraisal of the Casino gas field were all achieved within 14 months.

Observation of azimuthal shear wave anisotropy can be useful for characterization of fractures or stress fields. Shear wave anisotropy is often estimated by measuring splitting of individual shear wave events in vertical seismic profile (VSP) data. However, this method may become unreliable for zero-offset (marine) VSP where the seismogram often contains no strong individual shear events, such as direct downgoing shear wave, but often contains many low-amplitude PS mode converted waves. We have developed a new approach for estimation of the fast and slow shear wave velocities and orientation of polarization planes based on the multicomponent linear traveltime moveout velocity analysis. This technique is applicable to zero-offset VSP data, and should take advantage of the presence of a large number of shear wave events with the same apparent velocity (which, for a horizontally layered medium, should be close to the interval velocity). The approach assumes that the VSP data are acquired in a vertical well drilled in an orthorhombic medium with a horizontal symmetry plane (including horizontal transverse isotropy). The main idea is to estimate the dominant apparent velocity for a given polarization direction by measuring the coherency of the seismic signal of a large number of events as a function of the apparent velocity. The algorithm was tested on marine three-component (3C) VSP acquired in the North West Shelf of Australia, and on land 3C VSP acquired with different sources in the same borehole located in Otway Basin, Victoria. These tests show good agreement between anisotropy parameters (magnitude and orientation) derived from the VSP and cross-dipole sonic log data.

Abstract Better quantification of the spatiotemporal distribution of soil moisture across different spatial scales contributes significantly to the understanding of land surface processes on the Earth as an integrated system. While observational data for root-zone soil moisture (RZSM) often have sparse spatial coverage, model-simulated soil moisture may provide a useful alternative. TOPMODEL-Based Land Surface–Atmosphere Transfer Scheme (TOPLATS) has been widely studied and actively modified in recent years, while a detailed regional application with evaluation currently is still lacking. Thus, TOPLATS was used to generate high-resolution (30 arc s) RZSM based on coarse-scale (0.125°) forcing data over part of the Arkansas–Red River basin. First, the simulated RZSM was resampled to coarse scale to compare with the results of Mosaic, Noah, and VIC from NLDAS. Second, TOPLATS performance was assessed based on the spatial absolute difference among the models. The comparison shows that TOPLATS performance is similar to VIC, but different from Mosaic and Noah. Last, the simulated RZSM was compared with in situ observations of 16 stations in the study area. The results suggest that the simulated spatial distribution of RZSM is largely consistent with the distribution of topographic index (TI) in most instances, as topography was traditionally considered a major, but not the only, factor in horizontal redistribution of soil moisture. In addition, the finer-resolution RZSM can reflect the in situ soil moisture change at most local sites to a certain degree. The evaluation confirms that TOPLATS is a useful tool to estimate high-resolution soil moisture and has great potential to provide regional soil moisture estimates.

Abstract Challenges to manage and secure a sustainable water supply are expected to become more acute in Egypt as the lowermost riparian country of the Nile basin with the construction of new transboundary water infrastructures in Ethiopia and Sudan. To understand the impact of such transboundary water projects on Egypt, it is first necessary to develop a modeling tool that can simulate potential flow and reservoir scenarios inside Egypt without requiring in situ hydrologic or transboundary dam data that are typically unavailable. This study presents the water management value of a modeling framework to predict the current and future reservoir operating rules in the lower Nile basin using satellite Earth observations and hydrologic models. The platform comprises the Variable Infiltration Capacity (VIC) hydrologic model driven by high spatial and temporal resolution of satellite observations. Reservoir storage change is estimated using altimeter and visible imagery of lake area for Lake Nasser and then applied to infer reservoir operation for High Aswan Dam (HAD). The modeling framework based on satellite observations yielded a simulated streamflow at the outlet for Blue Nile basin (BNB) with a Nash–Sutcliffe efficiency of 0.68 with a correlation and RMSE of 0.94 and 1095 m3 s−1, respectively. Storage and outflow discharge of HAD were estimated for the period of 1998–2002 within 1.4% accuracy (0.076 km3 month−1) when compared with published reports. Because BNB controls the lion’s share of the variability to HAD inflow inside Egypt, the proposed modeling framework is appropriate for policy-makers to understand the implications of transboundary projects on the future water security of Egypt.

The success story of a shale-gas reserve development in the United States is triggering a strong industry focus towards similar plays in Australia. The Cooper Basin (located at the border of South Australia and Queensland) and the Otway Basin (extending both onshore and offshore South Australia and Victoria) could be prime targets to develop shale-gas projects. The Cooper Basin, a late-Carboniferous to mid-Triassic basin, is the largest onshore sedimentary basin producing oil and gas from tight conventional reservoirs with low permeability. Fracture stimulation programs are used extensively to produce the oil and gas. Furthermore, new exploration strategies are now targeting possible commercial gas hosted in low-permeability Permian shale units. To maximise production, the development of shale-gas prospects requires a good understanding of the: 1. structure of the reservoirs; 2. mechanical properties of the stratigraphy; 3. fracture geometry and density; 4. in-situ stress field; and, 5. fracture stimulation strategies. In this study, we use a combination of seismic mapping techniques–including horizon and attribute mapping, and an analysis of wellbore geophysical logs–to best constrain the existing fracture network in the basins. This study is based on the processing and analysis of a 3D seismic cube–the Moomba Big Lake survey–which is located in the southwestern part of the Cooper Basin. This dataset covers an area encompassing both a structurally complex setting in the vicinity of a major fault to the SE of the survey, and an area of more subtle deformation corresponding to the southernmost part of the Nappamerri Trough. Structural fabrics trending ˜NW–SE and NE–SW, which are not visible on the amplitude seismic data, are revealed by the analysis of the seismic attributes–namely a similarity (equivalent to a coherency cube), dip steering and maximum curvature attributes. These orientations are similar to those of natural fractures mapped from borehole images logs, and can therefore be interpreted as imaging natural fractures across the Moomba-Big Lake area. This study is the first of its kind able to detect possible fractures from seismic data in the Cooper Basin. The methodology developed here can offer new insights into the structure of sedimentary basins and provide crucial parameters for the development of tight reservoirs. In parallel, a tentative forward model of the generation of a fracture network following a restoration of the Top Roseneath horizon was carried out. The relatively good correlation between the fracture orientations generated by the model and the fractures mapped from geophysical data shows that fractures in the Moomba-Big Lake area may have formed during either a N–S compressive principal horizontal stress, or an E–W compressive principal horizontal tectonic stress regime. In addition, the orientations of the fracture interpreted through this study are also compatible with a generation under the present day stress regime described in this part of the basin, with an maximal horizontal stress trending E–W.

Abstract. The objective of this study is to assess the impacts of land cover change on the hydrological responses of the Mahanadi river basin, a large river basin in India. Commonly, such assessments are accomplished by using distributed hydrological models in conjunction with different land use scenarios. However, these models, through their complex interactions among the model parameters to generate hydrological processes, can introduce significant uncertainties to the hydrological projections. Therefore, we seek to further understand the uncertainties associated with model parameterization in those simulated hydrological responses due to different land cover scenarios. We performed a sensitivity-guided model calibration of a physically semi-distributed model, the Variable Infiltration Capacity (VIC) model, within a Monte Carlo framework to generate behavioural models that can yield equally good or acceptable model performances for subcatchments of the Mahanadi river basin. These behavioural models are then used in conjunction with historical and future land cover scenarios from the recently released Land-Use Harmonization version 2 (LUH2) dataset to generate hydrological predictions and related uncertainties from behavioural model parameterization. The LUH2 dataset indicates a noticeable increase in the cropland (23.3 % cover) at the expense of forest (22.65 % cover) by the end of year 2100 compared to the baseline year, 2005. As a response, simulation results indicate a median percent increase in the extreme flows (defined as the 95th percentile or higher river flow magnitude) and mean annual flows in the range of 1.8 % to 11.3 % across the subcatchments. The direct conversion of forested areas to agriculture (of the order of 30 000 km2) reduces the leaf area index, which subsequently reduces the evapotranspiration (ET) and increases surface runoff. Further, the range of behavioural hydrological predictions indicated variation in the magnitudes of extreme flows simulated for the different land cover scenarios; for instance, uncertainty in scenario labelled “Far Future” ranges from 17 to 210 m3 s−1 across subcatchments. This study indicates that the recurrent flood events occurring in the Mahanadi river basin might be influenced by the changes in land use/land cover (LULC) at the catchment scale and suggests that model parameterization represents an uncertainty which should be accounted for in the land use change impact assessment.

Abstract. The North West Himalayan basins have always been prone to hydro-meteorological disasters. Among them Beas Basin is one of the highly affected basins. Beas basin is prone to cloudburst which causes huge loss to life and property every year. Increase in these devastating events have been noticed in the recent years. Climatic change is considered as the major driver for this increased occurrence of these events in the recent past. The analysis of long-term hydrological extremes over the basin will help in understanding the pattern of the hydro-meteorological extremes and also predicting its nature in near and far future. The Variable Infiltration Capacity (VIC) model at the grid size of 0.025° × 0.025° has been used in the present study, for simulating the hydrological behaviour of the Beas Basin. The parameterization of the model inputs is derived from Remote Sensing based and field observed datasets. The model was forced with meteorological dataset of ERA-Interim for the past and present time period and CORDEX dataset for the future time period. The model was calibrated using observed discharge data of Nadaun and Sujanpur stations. The Nash-Sutcliffe model efficiency of calibrated model was achieved to be 0.77 and 0.72 and coefficient of determination (R2) was 0.80 and 0.72, respectively. The validation results of the model for the same stations shows the model efficiency to be 0.73 and 0.74 with coefficient of determination (R2) as 0.67 and 0.82, respectively. The well calibrated model was used to simulate the hydrological behaviour of historic period (1979–2000), present period (2001–2017), near future period (2018–2050) and far future period (2051–2099). The exceedance probability curve method has been utilized in estimating the flood peak value for the future time period. The flood peak discharge value for the future time period comes out to be 1050 m3/s. The hydro-meteorological extremes rate per year in each period was found to be 9, 9, 12 and 14, respectively. The hydro-meteorological extremes rate is showing increasing trend in near future and very high increase in far future. The study highlights the probability of occurrence of catastrophic events in coming future. The methodology and results of the present study can be beneficial for sustainable development of the basin to counter the effect of probable hydro-meteorological extremes in coming future.

China Shale-Gas Field Sets Production Record Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache and Total Plan Suriname Appraisals Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname. The company said another submission is expected for Kwaskwasi, the largest find in the block, by the end of the year. Operations continue for Keskesi, the fourth exploration target. There are plans to drill a fifth prospect at Bonboni in the North-Central portion of the concession. Partner company Total is assuming operatorship of the block ahead of next year’s campaigns. BP Emerges as Sole Bid for Offshore Canada Parcels BP was the only operator to place a bid in the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) Call for Bids NL20-CFB01, which offered 17 parcels (4,170,509 hectares) in the eastern Newfoundland region. The successful bid was for Parcel 9 (covering 264,500 hectares) for $27 million in work commitments from BP Canada Energy Group. Subject to BP satisfying specified requirements and receiving government approval, the exploration license will be issued in January 2021. No bids were received for the remaining 16 parcels, which may be reposted in a future Call for Bids. Criteria for selecting a winning bid is the total amount the bidder commits to spend on exploration of the parcel during the first period of a 9-year license, with a minimum acceptable bid of $10 million in work commitments for each parcel. Beach Energy To Drill Otway Basin Well Beach Energy plans to drill at its Artisan-1 well about 32 km offshore Victoria, Australia, in the Otway basin, before the end of 2021. The well, located on Block Vic/P43, was to be spudded in 1H 2020 but was delayed due to COVID-19. The timeframe for drilling was confirmed by the National Offshore Petroleum Safety and Environmental Management Authority, which also said Beach is keeping open the option to suspend the well and develop it, pending reservoir analysis. Anchors, mooring chains, and surface buoys have already been laid for the well, which is in a water depth of approximately 71 m. The well is expected to take approximately 35–55 days to drill, depending on the final work program and potential operational delays. Diamond Offshore’s semisubmersible Ocean Onyx was contracted for the drilling program. Artisan is the first of Beach’s planned multiwell campaigns, which also include development wells at the Geographe and Thylacine fields. Hess Completes Sale of Interest in Gulf of Mexico Field Hess completed the sale of its 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico (GOM) to BHP, the field’s operator, for $505 million. Shenzi is a six-lease development structured as a joint ownership: BHP (operator, 44%), Hess (28%), and Repsol (28%). The acquisition would bring BHP’s working interest to 72%, adding approximately 11,000 BOE/D of production (90% oil). The sale is expected to close by December 2020. Hess CEO John Hess said proceeds from the sale will help fund the company’s investment in Guyana. Greenland Opens New Offshore Areas Greenland opened three new offshore areas for application of oil and gas exploitation licenses off West Greenland. The areas are Baffin Bay, Disko West, and Davis Strait. The country also said it is working on an oil strategy to reduce geological uncertainty by offering an investment package to companies that engage in its Open Door Procedures. The procedures are a first-mover advantage to remove national oil company Nunaoil, as a carried partner, reducing turnover and surplus royalties. It is estimated to reduce the government take by 51.3% to 40.6%. Shell and Impact Oil & Gas Agree to South Africa Farmout Africa Oil announced Impact Oil & Gas entered into two agreements for exploration areas offshore South Africa. The company has a 31.10% share-holding in Impact, a privately owned exploration company. Impact entered into an agreement with BG International, a Shell subsidiary, for the farm-out of a 50% working interest and operatorship in the Transkei and Algoa exploration rights. Shell was also granted the option to acquire an additional 5% working interest should the joint venture (JV) elect to move into the third renewal period, expected in 2024. Algoa is located in the South Outeniqua Basin, east of Block 11B/12B, containing the Brulpadda gas condensate discovery and where Total recently discovered gas condensate. The Transkei block is northeast of Algoa in the Natal Trough Basin where Impact has identified highly material prospectivity associated with several large submarine fan bodies, which the JV will explore with 3D seismic data and then potential exploratory drilling. Impact and Shell plan to acquire over 6,000 km² of 3D seismic data during the first available seismic window following completion of the transaction. This window is expected to be in the Q1 2022. After the closing of the deal, Shell will hold a 50% interest as the operator and Impact will hold 50%. Impact also entered into an agreement with Silver Wave Energy for the farm-in of a 90% working interest and operatorship of Area 2, offshore South Africa. East and adjacent to Impact’s Transkei and Algoa blocks, Area 2 complements Impact’s existing position by extending the entire length of the ultradeepwater part of the Transkei margin. Together, the Transkei and Algoa Blocks and Area 2 cover over 124,000 km2. Area 2 has been opened by the Brulpadda and Luiperd discoveries in the Outeniqua Basin and will be further tested during 2021 by the well on the giant Venus prospect in ultradeepwater Namibia, where Impact is a partner. Impact believes there is good evidence for this Southern African Aptian play to have a common world-class Lower Cretaceous source rock, similar excellent-quality Apto-Albian reservoir sands, and a geological setting suitable for the formation of large stratigraphic traps. Following completion of the farm-in, Impact will hold 90% interest and serve as the operator; Silver Wave will hold 10%. Petronas Awards Sarawak Contract to Seismic Consortium The seismic consortium comprising PGS, TGS, and WesternGeco was awarded a multiyear contract by Petronas to acquire and process up to 105,000 km2 of multisensor, multiclient 3D data in the Sarawak Basin, offshore Malaysia. The contract award follows an ongoing campaign by the consortium in the Sabah offshore region, awarded in 2016, in which over 50,000 km2 of high-quality 3D seismic data have been acquired and licensed to the oil and gas industry to support Malaysia license round and exploration activity. The Sarawak award will allow for a multiphase program to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province). The consortium is planning the initial phases and is engaging with the oil and gas industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities. Total Discovers Second Gas Condensate in South Africa Total made a significant second gas condensate discovery on the Luiperd prospect, located on Block 11B/12B in the Outeniqua Basin, 175 km off the southern coast of South Africa. The discovery follows the adjacent play-opening Brulpadda discovery in 2019. The Luiperd-1X well was drilled to a total depth of about 3,400 m and encountered 73 m of net gas condensate pay in well-developed, good-quality Lower Cretaceous reservoirs. Following a coring and logging program, the well will be tested to assess the dynamic reservoir characteristics and deliverability. The Block 11B/12B covers an area of 19,000 km2, with water depths ranging from 200 to 1800 m. It is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR International (20%), and Main Street, a South African consortium (10%). The Luiperd prospect is the second to be drilled in a series of five large submarine fan prospects with direct hydrocarbon indicators defined utilizing 2D and 3D seismic data. BP Gas Field Offshore Egypt Begins Production BP started gas production from its Qattameya gasfield development ‎offshore Egypt in the North Damietta offshore concession. Through BP’s joint venture Pharaonic Petroleum Company working with state-owned Egyptian Natural Gas Holding Co., the field, which is ‎expected to produce up to 50 MMcf/D, was developed through a one-well subsea development and tieback to existing infrastructure.‎ Qattameya, whose discovery was announced in 2017, is located approximately 45 km west ‎of the Ha’py platform, in 108 m of water. It is tied back to the Ha’py and Tuart field ‎development via a new 50-km pipeline and connected to existing subsea ‎utilities via a 50-km umbilical. ‎BP holds 100% equity in the North Damietta offshore concession in the East Nile Delta. ‎Gas production from the field is directed to Egypt’s national grid.

AbstractHydrologic models predict the spatial and temporal distribution of water and energy at the land surface. Currently, parameter availability limits global-scale hydrologic modelling to very coarse resolution, hindering researchers from resolving fine-scale variability. With the aim of addressing this problem, we present a set of globally consistent soil and vegetation parameters for the Variable Infiltration Capacity (VIC) model at 1/16° resolution (approximately 6 km at the equator), with spatial coverage from 60°S to 85°N. Soil parameters derived from interpolated soil profiles and vegetation parameters estimated from space-based MODIS measurements have been compiled into input files for both the Classic and Image drivers of the VIC model, version 5. Geographical subsetting codes are provided, as well. Our dataset provides all necessary land surface parameters to run the VIC model at regional to global scale. We evaluate VICGlobal’s ability to simulate the water balance in the Upper Colorado River basin and 12 smaller basins in the CONUS, and their ability to simulate the radiation budget at six SURFRAD stations in the CONUS.

Abstract Transboundary rivers are often the cause of water related international disputes. One example is the Amu Darya River, with a catchment area of 470,000 km2, that passes through five countries and provides water resource for 89 million people. Intensified human activities and climate change in this region have altered hydrological processes and led to water related conflicts and ecosystem degradation. Understanding streamflow composition and quantifying the change impacts on streamflow in the Amu Darya Basin (ADB) are imperative to water resources management. Here, a degree-day glacier-melt scheme coupled offline with the Variable Infiltration Capacity hydrological model (VIC-glacier), forced by daily precipitation, maximum and minimum air temperature, and wind speed, is used to examine streamflow composition and changes during 1953–2019. Results show large differences in streamflow composition among the tributaries. There is a decrease in snow melt component (−260.8 m3 s−1) and rainfall component (−30.1 m3 s−1) at Kerki but an increase in glacier melt component (160.0 m3 s−1) during drought years. In contrast, there is an increase in snow melt component (378.6 m3 s−1) and rainfall component (12.0 m3 s−1) but a decrease in glacier melt component (−201.8 m3 s−1) during wet years. Using the VIC-glacier and climate elasticity approach, impacts of human activities and climate change on streamflow at Kerki and Kiziljar during 1956–2015 are quantified. Both methods agree and show a dominant role played by human activities in streamflow reduction, with contributions ranging 103.2– 122.1%; however, the contribution of climate change ranges in −22.1– −3.2%.