NEW INSIGHTS INTO THE ACTIVE PETROLEUM SYSTEMS IN THE COOPER AND EROMANGA BASINS, AUSTRALIA

1999 ◽  
Vol 39 (1) ◽  
pp. 263 ◽  
Author(s):  
C.J. Boreham ◽  
R.E. Summons
Keyword(s):  
Carbon Number ◽  
Carbon Isotopic Composition ◽  
Petroleum System ◽  
Source Rocks ◽  
Upper Permian ◽  
Geochemical Data ◽  
Indirect Measure ◽  
Petroleum Systems ◽  
Eromanga Basin ◽  
Cooper Basin

This paper presents geochemical data—gas chromatography, saturated and aromatic biomarkers, carbon isotopes of bulk fractions and individual n-alkanes—for oils and potential source rocks in the Cooper and Eromanga basins, which show clear evidence for different source-reservoir couplets. The main couplets involve Cooper Basin source and reservoir and Cooper Basin source and Eromanga Basin reservoir. A subordinate couplet involving Eromanga Basin source and Eromanga Basin reservoir is also identified, together with minor inputs from pre-Permian source rocks to reservoirs of the Cooper and Eromanga basins.The source–reservoir relationships are well expressed in the carbon isotopic composition of individual n-alkanes. These data reflect primary controls of source and maturity and are relatively insensitive to secondary alteration through migration fractionation and water washing, processes that have affected the molecular geochemistry of the majority of oils. Accordingly, the principal Gondwanan Petroleum Supersystem originating from a Permian source of the Cooper Basin has been further subdivided into two petroleum systems associated with Lower Permian Patchawarra Formation and Upper Permian Toolachee Formation sources respectively. Both sources are characterised by n-alkane isotope profiles that become progressively lighter with increasing carbon number—negative n-alkane isotope gradient. The Patchawarra source is isotopically lighter than the Toolachee source. Reservoir placement of oil in either the Toolachee or Patchawarra formations is, in general, a good guide to its source and perhaps an indirect measure of seal effectiveness. The subordinate Murta Petroleum Supersystem of the Eromanga Basin is subdivided into the Birkhead Petroleum System and Murta Petroleum System to reflect individual contributions from Birkhead Formation and Murta Formation sources respectively. Both systems are characterised by n-alkane carbon isotope profiles with low to no gradient. The minor Larapintine Petroleum Supersystem has been tentatively identified as involving pre-Permian source rocks in the far eastern YVarburton Basin and western margin of the Warrabin Trough in Queensland.Eromanga source inputs to oil accumulations in the Eromanga Basin can be readily recognised from saturated and aromatic biomarker assemblages. However, biomarkers appear to over-emphasise local Eromanga sources. Hence, we have preferred the semi-quantitative assessment of relative Cooper and Eromanga inputs that can be made using n-alkane isotope data and this appears to be robust provided that Eromanga source input is greater than 25% in oils of mixed origin. Enhanced contributions from Birkhead sources are concentrated in areas of thick and mature Birkhead source rocks in the northeastern Patchawarra Trough. Pre-Permian inputs are readily recognised by n-alkanes more depleted in I3C compared with late Palaeozoic and Mesozoic sources.Long range migration (>50 km) from Permian sources has been established for oil accumulations in the Eromanga Basin. This, together with contributions from local Eromanga sources, highlights petroleum pro- spectivity beyond the Permian edge of the Cooper Basin. Deeper, pre-Permian sources must also be considered in any petroleum system evaluation of the Cooper and Eromanga basins.

GEOCHEMICAL CHARACTERISTICS OF PALAEOZOIC PETROLEUM SYSTEMS IN NORTHWESTERN AUSTRALIA

1997 ◽  
Vol 37 (1) ◽  
pp. 351 ◽  
Author(s):  
D.S. Edwards ◽  
R.E. Summons ◽  
J.M. Kennard ◽  
R.S. Nicoll ◽  
J. Bradshaw ◽  
...  
Keyword(s):  
Fault Zone ◽  
Carbon Number ◽  
Isotopic Signature ◽  
Petroleum System ◽  
Upper Devonian ◽  
Source Rocks ◽  
Canning Basin ◽  
Petroleum Systems ◽  
Northwestern Australia ◽  
Biomarker Signature

Isotopic and biomarker analyses carried out on Cambrian to Permian oils and source rocks in the Arafura, Bonaparte (Petrel Sub-basin) and Canning Basins have been used to geochemically characterise five distinct petroleum systems within the Larapintine and Gondwanan Petroleum Supersystems. The Larapintine 1 Petroleum System is characterised by isotopically light, free hydrocarbons in the Arafura Basin (613Csat = −32 %o Arafura-1) which have been correlated to kerogens of similar isotopic signature within the Middle Cambrian Jigaimara Formation. The richness and maturity of these source rocks indicate that an effective Larapintine 1 Petroleum System may exist in the northern parts of the Arafura Basin. Larapintine 2 oils, with Gloeocapsomorpha prisca-type signatures, are found on the Barbwire- Dampier Terraces and Admiral Bay Fault Zone in the Canning Basin. These oils can be correlated to source rocks in the Lower Ordovician Goldwyer Formation on the Barbwire Terrace and the Bongabinni Formation in the Admiral Bay Fault Zone by their diagnostic odd- carbon-number preference in the C15—CJ9 n-alkanes. Larapintine 3 oils are derived from Upper Devonian marine carbonates in the Canning Basin and Petrel Sub- basin and have a diagnostic biomarker signature which includes a predominance of steranes relative to diasteranes and abundant gammacerane and 30- norhopanes, similar to those observed in the Upper Devonian Gogo and Pillara Formations. Larapintine 4 oils are derived from Lower Carboniferous marine, clay- rich mudstones in both the Petrel Sub-basin and Canning Basin. They are isotopically light (mean δ13C sat = −28 %o) and have a unique terpane signature which has been identified within the Milligans Formation. Gondwanan 1 Petroleum System hydrocarbons, represented here by the Petrel-4 condensate, have a heavy isotopic signature (δ13C sat = −24 %o) which, coupled with an abundance of the diasterane and diahopane biomarkers, indicates derivation from Permian deltaic source facies. Recognition of the diagnostic geochemical components of each Palaeozoic petroleum system has led to the identification of Permian-like isotopic signatres in some hydrocabon accumulations in the Timor Sea that were previously attributed to Mesozoic sources.

scholarly journals New data on oil and gas potential of the Vychegda Trough

Georesursy ◽  
2020 ◽  
Vol 22 (1) ◽  
pp. 32-38
Author(s):  
Tatyana V. Karaseva ◽  
Yury A. Yakovlev ◽  
Galina L. Belyaeva ◽  
Svetlana E. Bashkova
Keyword(s):  
Oil And Gas ◽  
Geological Structure ◽  
Petroleum System ◽  
Source Rocks ◽  
Upper Permian ◽  
Hydrocarbon Potential ◽  
Petroleum Potential ◽  
Petroleum Systems ◽  
Upper Riphean ◽  
European Part Of Russia

This article is devoted to the problem of studying the petroleum potential of the underexplored territories of the European part of Russia, in particular, the Vychegda trough. Taken a new approach to assessing the hydrocarbon potential of the Vychegda trough, based on the allocation of petroleum systems, widely used abroad. Based on a comprehensive analysis of the geological structure of the deflection and geological-geochemical results, including those obtained by the authors, two potential petroleum systems – “domanic” and “riphean” – were identified. The potential domanic petroleum system dominates in the Eastern regions and is a peripheral fragment of the regional petroleum system covering the territory of the Volga-Ural and Timan-Pechora basins. The system is linked to development in the South-Eastern part of the trough and the neighbouring Solikamsk depression of bituminous domanic and domanicoid sediments as a source rock, which is confirmed by the genetic correlation of crude oils of Devonian-Carboniferous deposits of the Northern districts of Solikamsk depression with domanic biomarker. The stratigraphic range of the domanic system is upper Devonian-upper Permian; the formation time is late Devonian-Mesozoic. The potential Riphean hydrocarbon system can be identified by the fact of oil-bitumen occurrences in the Proterozoic strata and the presence of the productive source rocks in the upper Riphean. The source rocks were at oil window. The Riphean system can cover the entire territory of the Vychegda trough, and the section from the Riphean to upper Permian sediments. The time of the system formation – Riphean-Mesozoic. Due to large thickness of the Riphean sediments, even with a large loss of hydrocarbon potential, the residual potential hydrocarbon resources of the Riphean petroleum system can be very significant. Based on the research conducted, prioritized exploration studies are substantiated.

Petroleum systems and results of exploration on the Atlantic margins of the UK, Faroes & Ireland: what have we learnt?

2016 ◽  
Vol 8 (1) ◽  
pp. 187-197 ◽  
Author(s):  
Iain C. Scotchman ◽  
Anthony G. Doré ◽  
Anthony M. Spencer
Keyword(s):  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Gas Field ◽  
Petroleum Systems ◽  
Unknown Source ◽  
Porcupine Basin ◽  
Break Up ◽  
Northern North Sea ◽  
The Uk

AbstractThe exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×109 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×109 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

Seeing through the dolerite-seismic imaging of petroleum systems, Tasmania, Australia

2015 ◽  
Vol 55 (1) ◽  
pp. 297
Author(s):  
Malcolm Bendall ◽  
Clive Burrett ◽  
Paul Heath ◽  
Andrew Stacey ◽  
Enzo Zappaterra
Keyword(s):  
Seismic Energy ◽  
Petroleum System ◽  
Source Rocks ◽  
Contact Metamorphism ◽  
Seismic Surveys ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Potential Reservoir ◽  
Frequency Sweeps ◽  
The Many

Prior to the onshore work of Empire Energy Corporation International (Empire) it was widely believed that the widespread sheets (>650 m thick) of Jurassic dolerite (diabase) would not only have destroyed the many potential petroleum source and reservoir rocks in the basin but would also absorb seismic energy and would be impossible to drill. By using innovative acquisition parameters, however, major and minor structures and formations can be identified on the 1,149 km of 2D Vibroseis. Four Vibroseis trucks were used with a frequency range of 6–140 Hz with full frequency sweeps close together, thereby achieving maximum input and return signal. Potential reservoir and source rocks may be seismically mapped within the Gondwanan Petroleum System (GPS) of the Carboniferous to Triassic Parmeener Supergroup in the Tasmania Basin. Evidence for a working GPS is from a seep of migrated, Tasmanite-sourced, heavy crude oil in fractured dolerite and an oil-bearing breached reservoir in Permian siliciclastics. Empire’s wells show that each dolerite sheet consists of several intrusive units and that contact metamorphism is usually restricted to within 70 m of the sheets’ lower margins. In places, there are two thick sheets, as on Bruny Island. One near-continuous 6,500 km2 sheet is mapped seismically across central Tasmania and is expected, along with widespread Permian mudstones, to have acted as an excellent regional seal. The highly irregular pre-Parmeener unconformity can be mapped across Tasmania and large anticlines (Bellevue and Thunderbolt prospects and Derwent Bridge Anticline) and probable reefs can be seismically mapped beneath this unconformity within the Ordovician Larapintine Petroleum System. Two independent calculations of mean undiscovered potential (or prospective) resources in structures defined so far by Empire’s seismic surveys are 596.9 MMBOE (millions of barrels of oil equivalent) and 668.8 MMBOE.

Observations on the Lower Triassic petroleum prospectivity of the offshore Carnarvon and Roebuck basins

2016 ◽  
Vol 56 (1) ◽  
pp. 173 ◽  
Author(s):  
Stephen Molyneux ◽  
Jeff Goodall ◽  
Roisin McGee ◽  
George Mills ◽  
Birgitta Hartung-Kagi
Keyword(s):  
Regional Analysis ◽  
Lower Triassic ◽  
Source Rocks ◽  
Upper Permian ◽  
Regional Study ◽  
North West ◽  
Petroleum Systems ◽  
The North ◽  
Depositional Processes ◽  
Water Margin

Why are the only commercial hydrocarbon discoveries in Lower Triassic and Permian sediments of the western margin of Australia restricted to the Perth Basin and the Petrel Sub-basin? Recent regional analysis by Carnarvon Petroleum has sought to address some key questions about the Lower Triassic Locker Shale and Upper Permian Chinty and Kennedy formations petroleum systems along the shallow water margin of the Carnarvon and offshore Canning (Roebuck/Bedout) basins. This paper aims to address the following questions:Source: Is there evidence in the wells drilled to date of a working petroleum system tied to the Locker Shale or other pre-Jurassic source rocks? Reservoir: What is the palaeogeography and sedimentology of the stratigraphic units and what are the implications for the petroleum systems?The authors believed that a fresh look at the Lower Triassic to Upper Permian petroleum prospectivity of the North West Shelf would be beneficial, and key observations arising from the regional study undertaken are highlighted:Few wells along a 2,000 km area have drilled into Lower Triassic Locker Shale or older stratigraphy. Several of these wells have been geochemically and isotopically typed to potentially non Jurassic source rocks. The basal Triassic Hovea Member of the Kockatea Shale in the Perth Basin is a proven commercial oil source rock and a Hovea Member Equivalent has been identified through palynology and a distinctive sapropelic/algal kerogen facies in nearly 16 wells that penetrate the full Lower Triassic interval on the North West Shelf. Samples from the Upper Permian, the Hovea Member Equivalent and the Locker Shale have been analysed isotopically indicating –28, –34 and –30 delta C13 averages, respectively. Lower Triassic and Upper Permian reservoirs are often high net to gross sands with up to 1,000 mD permeability and around 20% porosity. Depositional processes are varied, from Locker Shale submarine canyon systems to a mixed carbonate clastic marine coastline/shelf of the Upper Permian Chinty and Kennedy formations.

PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

2000 ◽  
Vol 40 (1) ◽  
pp. 26
Author(s):  
M.R. Bendall C.F. Burrett ◽  
H.J. Askin
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Late Triassic ◽  
Upper Permian ◽  
Lower Permian ◽  
Peak Oil ◽  
Petroleum Systems ◽  
Upper Proterozoic ◽  
Oil Seep

Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.

3D basin and petroleum system modelling in the North Sea Central Graben - a Dutch, German, Danish cross-border study

2020 ◽  
Author(s):  
Rüdiger Lutz ◽  
Jashar Arfai ◽  
Susanne Nelskamp ◽  
Anders Mathiesen ◽  
Niels Hemmingsen Schovsbo ◽  
...  
Keyword(s):  
Pilot Study ◽  
North Sea ◽  
Large Scale ◽  
Petroleum System ◽  
Source Rocks ◽  
System Model ◽  
Geochemical Data ◽  
System Modelling ◽  
Horizon 2020 ◽  
Cross Border

<p>A Geological Analysis and Resource Assessment of selected Hydrocarbon Systems (GARAH) is carried out as part of the overarching GeoERA project. Here, we report first results of a 3D basin and petroleum system model developed in a cross-border area of the Dutch, Danish and German North Sea Central Graben area. This pilot study reconstructs the thermal history, maturity and petroleum generation of potential Lower, Middle and Upper Jurassic source rocks. The 3D pilot study incorporates new aggregated and combined layers from the three countries. Results of the study feed back into the 3DGEO-EU project of GeoERA.</p><p>Eight key horizons covering the whole German Central Graben and parts of the Dutch and Danish North Sea Central Graben were selected for building the stratigraphic and geological framework of the 3D basin and petroleum system model. The model includes depth and thickness maps of important stratigraphic units as well as the main salt structures. Petrophysical parameters, generalized facies information and organic geochemical data from well reports are assigned to the different key geological layers. The model is further calibrated with temperature and maturity data from wells of the three countries and from publications. The time span from the Late Permian to the Present is represented by the model including the most important erosional phases related to large-scale tectonic events during the Late Jurassic to Late Cretaceous. Additionally, salt movement through time expressed as diapirs and pillows is considered within the 3D basin and petroleum system model.</p><p>This is a part of an ongoing EU Horizon 2020 GeoERA project (The GARAH, H2020 grant #731166 lead by GEUS).</p>

PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA

2007 ◽  
Vol 47 (1) ◽  
pp. 127 ◽  
Author(s):  
G. Ambrose ◽  
M. Scardigno ◽  
A.J. Hill
Keyword(s):  
Oil And Gas ◽  
Regional Scale ◽  
Early Jurassic ◽  
Source Rocks ◽  
Late Triassic ◽  
Red Beds ◽  
Petroleum Systems ◽  
Stratigraphic Architecture ◽  
Central Australia ◽  
Cooper Basin

Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.

Cooper Basin source rock atlas

2016 ◽  
Vol 56 (2) ◽  
pp. 594
Author(s):  
Lisa Hall ◽  
Tehani Palu ◽  
Chris Boreham ◽  
Dianne Edwards ◽  
Tony Hill ◽  
...  
Keyword(s):  
Spatial Distribution ◽  
Source Rock ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Predictive Tool ◽  
Resource Potential ◽  
Petroleum Systems ◽  
Petroleum Resource ◽  
Hydrocarbon Yield ◽  
Cooper Basin

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

Pre-Messinian Petroleum Systems and Trap Style in the Offshore Western of Nile Delta; An Integrated Geological and Geophysical Approach

2016 ◽  
Author(s):  
Mostafa Monir ◽  
Omar Shenkar
Keyword(s):  
Seismic Data ◽  
Nile Delta ◽  
Lower Pressure ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Geochemical Data ◽  
Peak Oil ◽  
West Nile ◽  
Petroleum Systems ◽  
Well Data

ABSTRACT Exploration in the offshore Nile Delta province has revealed several hydrocarbon plays. Deep marine Turbidites is considered one of the most important plays for hydrocarbon exploration in the Nile Delta. These turbidites vary from submarine turbidite channels to submarine basin floor fans. An integrated exploration approach was applied for a selected area within West Delta Deep Marine (WDDM) Concession offshore western Nile Delta using a variety of geophysical, geological and geochemical data to assess the prospectivity of the Pre-Messinian sequences. This paper relies on the integration of several seismic data sets for a new detailed interpretation and characterization of the sub-Messinian structure and stratigraphy based on regional correlation of seismic markers and honoured the well data. The interpretation focused mainly on the Oligocene and Miocene mega-sequences. The seismic expression of stratigraphic sequences shows a variety of turbidite channel/canyon systems having examples from West Nile delta basin discoveries and failures. The approach is seismically based focusing on seismic stratigraphic analysis, combination of structure and stratigraphic traps and channels interpretation. Linking the geological and geophysical data together enabled the generation of different sets of geological models to reflect the spatial distribution of the reservoir units. The variety of tectonic styles and depositional patterns in the West Nile delta provide favourable trapping conditions for hydrocarbon generations and accumulations. The shallow oil and gas discoveries in the Pliocene sands and the high-grade oils in the Oligo-Miocene and Mesozoic reservoirs indicate the presence of multiple source rocks and an appropriate conditions for hydrocarbon accumulations in both biogenic and thermogenic petroleum systems. The presence of multi-overpressurized intervals in the Pliocene and Oligo-Miocene Nile delta stratigraphic column increase the depth oil window and the peak oil generation due to decrease of the effective stress. Fluids have the tendency to migrate from high pressure zones toward a lower pressure zones, either laterally or vertically. Also, hydrocarbons might migrate downward if there is a lower pressure in the deeper layers. Well data and the available geochemical database have been integrated with the interpreted seismic data to identify potential areas of future prospectivity in the study area.

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