Basin-to-prospect-scale subsurface characterisation: new insights into the Exmouth Sub-basin, North West Shelf, Australia

2021 ◽  
Vol 61 (2) ◽  
pp. 640
Author(s):  
Abdul Kholiq ◽  
Claire Jacob ◽  
Bee Jik Lim ◽  
Oliver Schenk ◽  
Anubrati Mukherjee ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Upper Jurassic ◽  
Hydrocarbon Exploration ◽  
Primary Study ◽  
Rift System ◽  
Study Objective ◽  
North West ◽  
Northern Carnarvon Basin ◽  
Primary Study Objective ◽  
Hydrocarbon Charge

The Exmouth Sub-basin represents part of the intracratonic rift system of the northern Carnarvon Basin, Australia. Hydrocarbon exploration has resulted in the discovery of a variety of oil and gas accumulations, mainly in Upper Triassic, Upper Jurassic and Lower Cretaceous intervals. Recent 3D petroleum systems modelling aided in understanding the interaction of the complex basin evolution and hydrocarbon charge history, shedding light on the variety and distribution of hydrocarbon types encountered, whilst also highlighting future remaining potential in both proven and untested plays. As a result of this modelling, the Exmouth Subsurface Characterisation Study was commissioned to further leverage >12000km2of recently acquired and processed seismic data and integrate data from specifically conditioned wells from across the Exmouth Sub-basin. The primary study objective was to better understand the distribution of lithologies across the basin, with focus upon the reservoir presence and properties over proven and potential deeper sections. Furthermore, given the variety of hydrocarbon types encountered, this study set out to understand the amplitude behaviour of these types within the different reservoirs. Collectively, these results have aided in identifying analogous hydrocarbon amplitude responses across the basin, derisking identified plays, prospects and existing discoveries and fields whilst also identifying new plays and leads.

Estimating smectite content from seismic data

2019 ◽  
Vol 59 (2) ◽  
pp. 851
Author(s):  
Roman Beloborodov ◽  
Marina Pervukhina ◽  
Valeriya Shulakova ◽  
Dimitri Chagalov ◽  
Matthew Josh ◽  
...  
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Clay Mineralogy ◽  
Mineralogical Composition ◽  
Hydrocarbon Exploration ◽  
Seismic Survey ◽  
Maximum Deviation ◽  
North West ◽  
Northern Carnarvon Basin ◽  
Carnarvon Basin

Predicting the mineralogical composition of shales is crucial for drilling operations related to hydrocarbon exploration/production as well as for the assessment of their sealing capacity as hydrocarbon or CO2 barriers. For example, hydrocarbon exploration in the Northern Carnarvon Basin, North-West Shelf, Australia is hindered by the presence of a thick (up to 1 km) smectite-rich shale seal that spreads regionally. Complex structures of the channelised oil and gas fields in the area make it necessary to drill deviated wells through that seal. The maximum deviation angle at which successful drilling is possible depends strongly on the clay mineralogy and, in particular, on the smectite content in the shale. Here, we introduce a novel workflow combining seismic data, well logs and laboratory measurements to infer shale composition at the reservoir scale. It is applied to the Duyfken 3D seismic survey in the central part of the Northern Carnarvon Basin. Interpretation results are verified against the laboratory X-ray diffraction measurements from the test well that was not used for the interpretation. The results match the test data well within the determined uncertainty bounds.

Comprehensive basin-wide 3D petroleum systems modelling providing new insights into proven petroleum systems and remaining prospectivity in the Exmouth Sub-basin, Australia

2020 ◽  
Vol 60 (2) ◽  
pp. 753
Author(s):  
Oliver Schenk ◽  
Craig Dempsey ◽  
Robbie Benson ◽  
Michael Cheng ◽  
Sugandha Tewari ◽  
...  
Keyword(s):  
Early Cretaceous ◽  
Late Jurassic ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Long Distance ◽  
North West ◽  
Petroleum Systems ◽  
Northern Carnarvon Basin ◽  
Hydrocarbon Expulsion

The Exmouth Sub-basin is part of the Northern Carnarvon Basin, offshore north-west Australia, and has undergone a complex tectonic history. Hydrocarbon exploration resulted in the discovery of a variety of oil and gas accumulations; however, their distribution and charge history from different petroleum systems is still poorly understood due to limited knowledge of the deeper basin architecture. The basin-wide, long-offset, broadband 2017 Exmouth 3D multiclient seismic dataset allowed a seamless interpretation into this deeper section. This work revealed new insights on the tectono-stratigraphic evolution of the Exmouth Sub-basin. Mesozoic extension, that was restricted to the latest Triassic, was followed by a sag phase with homogeneous, shale-dominated deposition, resulting in source rock potential for the entire Jurassic section. These findings, together with potential field modelling, were integrated into this first basin-wide 3D petroleum system model to better constrain the thermal history and petroleum systems. The model improved our understanding of the complex charge history of hydrocarbon fields. It predicts that hydrocarbon expulsion from Late Jurassic source rocks continued into the Late Cretaceous, a period when the regional Early Cretaceous Muderong Formation was an efficient seal rock. This implies that, in addition to long-distance, sub-Muderong migration, vertical, short-distance migration may have contributed significant petroleum charge to the discovered accumulations in the southern Exmouth Sub-basin. The model also predicts additional prospective areas: fault-seal structures within Early Cretaceous intervals north of the Novara Arch, intra-formational Late Jurassic sandstones north of the current fields (with low biodegradation risk) and Triassic reservoirs along the basin margins and north of the Jurassic depocentre.

scholarly journals Comparison of Short- versus Long-Course Antimicrobial Therapy of Uncomplicated Bacterial Pneumonia in Dogs: A Double-Blinded, Placebo-Controlled Pilot Study

Animals ◽  
2021 ◽  
Vol 11 (11) ◽  
pp. 3096
Author(s):  
Aida I. Vientós-Plotts ◽  
Isabelle Masseau ◽  
Carol R. Reinero
Keyword(s):  
Pilot Study ◽  
Antimicrobial Therapy ◽  
Bacterial Pneumonia ◽  
Clinical Signs ◽  
Current Treatment ◽  
Controlled Study ◽  
Primary Study ◽  
Study Objective ◽  
Primary Study Objective ◽  
Double Blinded

Current treatment for canine bacterial pneumonia relies on protracted courses of antimicrobials (3–6 weeks or more) with recommendations to continue for 1–2 weeks past resolution of all clinical and thoracic radiographic abnormalities. However, in humans, bacterial pneumonia is often treated with 5–10-day courses of antimicrobials, and thoracic radiographs are not considered useful to guide therapeutic duration. The primary study objective was to determine whether a short course of antimicrobials would be sufficient to treat canine bacterial pneumonia. Eight dogs with uncomplicated bacterial pneumonia were enrolled in this randomized, double-blinded, placebo-controlled study comparing clinical and radiographic resolution with differing durations of antimicrobial therapy. Dogs received a course of antimicrobials lasting 10 (A10) or 21 (A21) days. Dogs randomized to the A10 group received placebo for 11 days following antimicrobial therapy. Patients were evaluated at presentation and 10, 30 and 60 days after the initiation of antimicrobials. At 10 days, 6/8 dogs had resolution of both clinical signs and inflammatory leukogram, and 5/8 dogs had improved global radiographic scores. After 60 days, clinical and hematologic resolution of pneumonia was noted in all dogs regardless of antimicrobial therapy duration; however, 3/8 dogs had persistent radiographic lesions. Thoracic radiographs do not appear to be a reliable marker to guide antimicrobial therapy in canine bacterial pneumonia as radiographic lesions may lag or persist despite clinical cure. This pilot study suggests a 10-day course of antimicrobials may be sufficient to treat uncomplicated canine bacterial pneumonia.

Early Production Life of Wheatstone Project Offshore Australia Yields Key Lessons

2021 ◽  
Vol 73 (08) ◽  
pp. 51-52
Author(s):  
Chris Carpenter
Keyword(s):  
Oil And Gas ◽  
Asia Pacific ◽  
North West ◽  
The North ◽  
Sand Control ◽  
Single Well ◽  
Early Production ◽  
Northern Carnarvon Basin ◽  
Shelf Region ◽  
Gas Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202246, “Wheatstone: What We Have Learned in Early Production Life,” by John Pescod, SPE, Paul Connell, SPE, and Zhi Xia, Chevron, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Asset Overview Chevron Australia’s Wheatstone project is in the North West Shelf region offshore Australia (Fig. 1). Two gas fields, Wheatstone and Iago (along with a field operated by a different company), currently tie into the WP in the Northern Carnarvon Basin. These two gas fields are in water depths between 150 and 400 m. The platform processes gas and condensate through dehydration and compression facilities before export by a 220-km, 44-in., trunkline to two 4.45-million-tonnes/year LNG trains and a 200 tera-joule/day domestic gas plant. A Wheatstone/Iago subsea system consisting of two main corridors delivers production from north and south of the Wheatstone and Iago fields to the WP. Currently, the subsea system consists of nine subsea foundation development wells, three subsea production manifolds, two subsea 24-in. production flowlines, and two subsea 14-in. utility lines. The nine foundation development wells feed the subsea manifolds at rates of up to 250 MMscf/D. These wells have openhole gravel-pack completions for active sand control and permanent downhole gauges situated approximately 1000-m true vertical depth above the top porosity of multi-Darcy reservoir intervals for pressure and temperature monitoring. All wells deviate between 45 and 60° through the reservoir with stepout lengths of up to 2.5 km. The two subsea 24-in. production flowlines carry production fluids from the subsea manifolds to two separation trains on the WP. Each platform inlet production separator can handle up to 800 MMscf/D. The two 14-in. utility flowlines installed to the subsea manifolds allow routing of a single well to the platform multiuse header, which can direct flow into the multiuse separator (MUS) or other production separators at a rate of 250 MMscf/D.

3D Seismic classification of Fluid Escape Pipes in the western Exmouth Plateau, North West Shelf of Australia (A)

2020 ◽  
pp. jgs2020-096
Author(s):  
Susy Mercado Ruge ◽  
Nicola Scarselli ◽  
Awad Bilal
Keyword(s):  
Fluid Flow ◽  
Significant Risk ◽  
Sedimentary Basins ◽  
Upper Jurassic ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Reflection Data ◽  
North West ◽  
Exmouth Plateau ◽  
Northern Carnarvon Basin

Fluid escape pipes are vertical pathways of focused flow venting from a variety of deep overpressure sources. These geological features are typical of many sedimentary basins, including proven petroliferous provinces worldwide, such as the North Sea and the Exmouth Plateau in the Northern Carnarvon Basin, Northwest Australia. High quality three-dimensional (3D) seismic reflection data from the western Exmouth Plateau revealed the occurrence of exceptionally well-imaged fluid escape pipes affecting the Jurassic strata and the Triassic Mungaroo Formation, a key reservoir unit in the basin. A total of 171 fluid escape pipes, including blowout, seepage and hydrothermal pipes, were mapped, and their geomorphic characteristics were analysed. In the study area, these features form prominent vertical columns up to 4.5 km long disrupting continuous reflections of the Triassic to Jurassic section. Numerous fluid escape pipes terminate with paleo-pockmarks affecting at the Upper Jurassic syn-extension strata, providing evidence for pipe genesis during the early stages of the Late Jurassic rifting in the Exmouth Plateau . Fluid escape pipes were found rooting from different stratigraphic levels, suggesting multiple fluid sources within the Triassic sediments. Several fluid flow structures nucleated along or nearby rift-related fault planes within the Mungaroo Formation providing further evidence of rifting as a main triggering factor of important fluid flow in the basin.In the study area, the presence of fluid escape pipes represents a significant risk for the preservation of potential hydrocarbons accumulations as when these features form, vertical fluid venting breaches through stratigraphy compromising the integrity of seal units. This seems supported by the lack of significant discoveries within the area covered by seismic survey analysed in this research.

An integrated evaluation of hydrocarbon charge and retention at the Griffin, Chinook, and Scindian oil and gas fields, Barrow Subbasin, North West Shelf, Australia

AAPG Bulletin ◽  
2006 ◽  
Vol 90 (9) ◽  
pp. 1359-1380 ◽  
Author(s):  
Mark Brincat ◽  
Anthony Gartrell ◽  
Mark Lisk ◽  
Wayne Bailey ◽  
Luke Johnson ◽  
...  
Keyword(s):  
Oil And Gas ◽  
North West ◽  
Oil And Gas Fields ◽  
Hydrocarbon Charge ◽  
Gas Fields

scholarly journals Changes in snow cover occurrence and the atmospheric circulation impact in Poznań (Poland)

2021 ◽  
Author(s):  
Katarzyna Szyga-Pluta
Keyword(s):  
Snow Cover ◽  
Atmospheric Circulation ◽  
Thermal Conditions ◽  
Severity Index ◽  
Primary Study ◽  
Winter Period ◽  
Study Objective ◽  
Primary Study Objective ◽  
The Impact ◽  
Winter Severity

AbstractThe variability of occurrence of snow cover and the impact of atmospheric circulation on the snow cover occurrence in the period 1966/1967–2019/2020 in Poznań (Poland) have been examined. The implementation of the primary study objective covers the comprehensive analysis of the winter snow and thermal conditions using various indicators. This paper is based on daily data from the years 1966–2020 concerning the winter period. Winters in Poznań are highly variable and differentiated, considering the duration of particular seasons, number of days with snow cover, mean snow cover thickness, winter snowiness coefficient, or winter severity index. Negative trends concerning days with snow cover total snow cover depth winter snowiness coefficient and winter severity index in Poznań prove statistically significant. A higher probability of occurrence of snow cover was determined during cyclonic than anticyclonic circulation. The westerly and northerly types especially favoured the occurrence of days with snow cover. The increase of snow cover was associated with the northerly inflow mainly. Westerly types of circulation caused the decrease of snow cover predominantly.

The petroleum prospectivity of the Oobagooma Sub-basin and adjacent Leveque Platform, North West Shelf, Australia

2016 ◽  
Vol 56 (2) ◽  
pp. 563
Author(s):  
Paul Harrison ◽  
Chris Swarbrick ◽  
Jim Winterhalder ◽  
Mark Ballesteros
Keyword(s):  
Oil And Gas ◽  
Long Distance ◽  
The West ◽  
North West ◽  
Canning Basin ◽  
The Past ◽  
The North ◽  
Late Tertiary ◽  
Exploration Drilling ◽  
Hydrocarbon Charge

The Oobagooma Sub-basin of the Roebuck Basin includes the offshore extension of the onshore Fitzroy Trough of the Canning Basin. Together with the Leveque Platform, it covers an area of approximately 50,000 km2, yet only 14 exploration wells have been drilled in the area to date, five of which were drilled in the past 30 years. The sub-basin contains sediments ranging in age from Ordovician to Recent. This study examines the petroleum prospectivity of a region that is one of the least explored on Australia’s North West Shelf. Recent exploration drilling has revived interest in the area, with the 2014 Phoenix South–1 oil discovery in the offshore Bedout Sub-basin and the 2015 Ungani Far West–1 oil discovery in the onshore Fitzroy Trough. The two most significant source rock sequences relevant to the Oobagooma Sub-basin are the Carboniferous Laurel Formation and the Jurassic section. The former interval is part of a proven petroleum system onshore and is the source of the gas discovered at Yulleroo and oil at Ungani and Ungani Far West. A thick Jurassic trough to the north of the Oobagooma Sub-basin is believed to be the source of the oil and gas in Arquebus–1A and gas in Psepotus–1. Hydrocarbon charge modelling indicates significant expulsion occurred during both the Cretaceous and Tertiary from both source intervals. Trap timing is generally favourable given that inversion structures formed in several episodes during the Late Jurassic to Late Tertiary. The Early Triassic, now proven to be oil prone in the Phoenix South area (Molyneux et al, 2015), provides an additional (albeit less likely) source for the Oobagooma Sub-basin. These rocks are thin to absent within the Oobagooma Sub-basin, so long-distance migration would be required from deep troughs to the west.

Tailored acquisition and processing providing an enhanced subsurface image of the basin architecture, Exmouth Sub-basin, North West Shelf, Australia

2019 ◽  
Vol 59 (2) ◽  
pp. 886
Author(s):  
Alexander Karvelas ◽  
Bee Jik Lim ◽  
Lianping Zhang ◽  
Haryo Trihutomo ◽  
Oliver Schenk ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Model Building ◽  
Waveform Inversion ◽  
Hydrocarbon Exploration ◽  
Surface Velocity ◽  
Seismic Survey ◽  
Image Point ◽  
Surface Model ◽  
Near Surface ◽  
North West

Hydrocarbon exploration has resulted in the discovery of a variety of oil and gas accumulations mainly in Upper Jurassic and Lower Cretaceous intervals. However, the distribution of the different petroleum system elements including Jurassic and Triassic intervals is poorly determined, but required for improved understanding of the complex charge history, as indicated by the variety of hydrocarbon types encountered in the basin. The new WesternGeco multiclient 3D seismic survey extends to the edges of the basin to give a comprehensive picture. Raw hydrophone data were delivered from the vessel as acquisition progressed to begin the near-surface model building. The model building consisted of two major stages: first, using full waveform inversion (FWI) to derive the near-surface velocity field; and, second, common image point (CIP) tomography to update the deeper section beyond the FWI illumination zone. As illustrated herein, various stages of processing and imaging provided a cleaner and crisper dataset across the record length, allowing (1) detailed picking of the events within the entire Mesozoic (Cretaceous–Triassic) section allowing key events to be interpreted and correlated across the area and (2) accurate investigation of the complexity of different aged fault networks and their relationships across the full Exmouth Sub-basin for the first time. In summary, this survey provides a detailed insight into the deeper basin architecture of the Exmouth Sub-basin. The seamless volume imaged to depth allows accurate mapping which is critical to unravel the complex evolutionary history in a basin with proven and significant remaining hydrocarbon potential.

IDENTIFICATION AND INTERPRETATION OF LEAKING HYDROCARBONS USING SEISMIC DATA:A COMPARATIVE MONTAGE OF EXAMPLES FROM THE MAJOR FIELDS IN AUSTRALIA'S NORTHWEST SHELF AND GIPPSLAND BASIN

2000 ◽  
Vol 40 (1) ◽  
pp. 119 ◽  
Author(s):  
R. Cowley ◽  
G.W. O'Brien
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Hydrocarbon Migration ◽  
North West ◽  
Seal Integrity ◽  
Seismic Amplitudes ◽  
Gas Chimneys ◽  
Hydrocarbon Charge ◽  
Gippsland Basin ◽  
Carnarvon 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.

Sign in / Sign up

Export Citation Format

Share Document