scholarly journals 3D basin and petroleum system modelling of the NW German North Sea (Entenschnabel)

2017 ◽  
Vol 8 (1) ◽  
pp. 67-86 ◽  
Author(s):  
Jashar Arfai ◽  
Rüdiger Lutz
Keyword(s):  
Heat Flow ◽  
North Sea ◽  
Late Jurassic ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
System Modelling ◽  
Gas Field ◽  
Posidonia Shale

Abstract3D basin and petroleum system modelling covering the NW German North Sea (Entenschnabel) was performed to reconstruct the thermal history, maturity and petroleum generation of three potential source rocks, namely the Namurian–Visean coals, the Lower Jurassic Posidonia Shale and the Upper Jurassic Hot Shale.Modelling results indicate that the NW study area did not experience the Late Jurassic heat flow peak of rifting as in the Central Graben. Therefore, two distinct heat flow histories are needed since the Late Jurassic to achieve a match between measured and calculated vitrinite reflection data. The Namurian–Visean source rocks entered the early oil window during the Late Carboniferous, and reached an overmature state in the Central Graben during the Late Jurassic. The oil-prone Posidonia Shale entered the main oil window in the Central Graben during the Late Jurassic. The deepest part of the Posidonia Shale reached the gas window in the Early Cretaceous, showing maximum transformation ratios of 97% at the present day. The Hot Shale source rock exhibits transformation ratios of up to 78% within the NW Entenschnabel and up to 20% within the Central Graben area. The existing gas field (A6-A) and oil shows in Chalk sediments of the Central Graben can be explained by our model.

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.

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>

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

2021 ◽  
Author(s):  
Rüdiger Lutz ◽  
Susanne Nelskamp ◽  
Anders Mathiesen ◽  
Niels Hemmingsen Schovsbo ◽  
Stefan Ladage ◽  
...  
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 results on the first public 3D basin and petroleum system model developed in a cross-border area of the Dutch, Danish and German North Sea Central Graben. This pilot study reconstructs the thermal history, maturity and petroleum generation of potential Lower, Middle and Upper Jurassic source rocks and assesses potential unconventional resources in a first phase. The 3D pilot study incorporates new aggregated and combined layers of 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. Further, the model is calibrated with temperature and maturity data from selected offshore wells as well as 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. Simulations depict that unconventional petroleum resources (oil and natural gas) are present in varying amounts in the source rocks across all three countries.</p><p>This is a part of an ongoing EU Horizon 2020 GeoERA project (The GARAH, H2020 grant #731166 lead by GEUS).</p>

The systematic position of the Late Jurassic alleged dinosaur Macelognathus (Crocodylomorpha: Sphenosuchia)

2005 ◽  
Vol 42 (3) ◽  
pp. 307-321 ◽  
Author(s):  
Ursula B Göhlich ◽  
Luis M Chiappe ◽  
James M Clark ◽  
Hans-Dieter Sues
Keyword(s):  
Late Jurassic ◽  
Upper Jurassic ◽  
Systematic Position ◽  
Lower Jurassic ◽  
Late Triassic ◽  
Morrison Formation ◽  
Postcranial Skeleton ◽  
Western Colorado ◽  
New Material ◽  
Limb Posture

Macelognathus vagans was described by O.C. Marsh in 1884, based on a mandibular symphysis from the Upper Jurassic Morrison Formation of Wyoming. Often considered a dinosaur but later tentatively referred to the Crocodylia, its phylogenetic identity has until now been enigmatic. New material of this species from the Morrison Formation of western Colorado demonstrates its affinities with basal crocodylomorphs commonly grouped together as the Sphenosuchia, which are characterized by a gracile postcranial skeleton with erect limb posture. Macelognathus shares features with Kayentasuchus from the Lower Jurassic Kayenta Formation of Arizona and Hallopus, which may be from the Morrison Formation of eastern Colorado. The new material constitutes the youngest definitive occurrence of a sphenosuchian, previously known from the Late Triassic to the Middle or Late? Jurassic.

Ordering of illite-smectite in Upper Jurassic Claystones from the North Sea

Clay Minerals ◽  
1991 ◽  
Vol 26 (1) ◽  
pp. 105-125 ◽  
Author(s):  
H. Lindgreen ◽  
P. L. Hansen
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Depth Interval ◽  
Peak Oil ◽  
Bulk Rock ◽  
Transformation Mechanism ◽  
Rock Samples ◽  
The North ◽  
Central Trough

AbstractUpper Jurassic claystones of Kimmeridgian-Volgian(-Ryazanian) age are the main source rocks for oil in the Central Trough, North Sea. Drill cuttings and cores from the depth interval 2368–4548 m, the interval from early-mature to peak oil generation, have been investigated by high-resolution transmission electron microscopy (HRTEM) of ion-milled rock samples, and by HRTEM and powder X-ray diffraction (XRD) of dispersed illite-smectite (I-S) mixed-layers isolated from the <0·2 µm fraction. Ordering parameters were determined by XRD profile simulation. TEM on shadowed particles, combined with XRD evidence, showed that dispersed I-S consists of a mixture of 10–70 Å thick particles, whereas HRTEM showed that intact bulk rock was dominated by 50–200 Å thick particles. Disruption, possibly along smectite planes, of the larger particles in the bulk rock formed the thin particles in dispersed I-S. HRTEM showed 20 and 30 Å periodic enhancement in the contrast of lattice fringes in bulk rock samples as well as in dispersed I-S crystals. These features were interpreted as ordered I-S crystals. Indications of disintegration of larger I-S particles during sample dispersion and of the presence of ordered I-S crystals in the intact bulk rock support the layer transformation mechanism for the conversion of smectite to illite.

scholarly journals Analysis of Petroleum System for Exploration and Risk Reduction in Abu Madi/Elqar'a Gas Field, Nile Delta, Egypt

2012 ◽  
Vol 2012 ◽  
pp. 1-10 ◽  
Author(s):  
Said Keshta ◽  
Farouk J. Metwalli ◽  
H. S. Al Arabi
Keyword(s):  
Nile Delta ◽  
Organic Matter Content ◽  
Petroleum System ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Basin Modeling ◽  
Burial History ◽  
Gas Field ◽  
Upper Miocene ◽  
Migration Pathways

Abu Madi/El Qar'a is a giant field located in the north eastern part of Nile Delta and is an important hydrocarbon province in Egypt, but the origin of hydrocarbons and their migration are not fully understood. In this paper, organic matter content, type, and maturity of source rocks have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. Modeling of the empirical data of source rock suggests that the Abu Madi formation entered the oil in the middle to upper Miocene, while the Sidi Salem formation entered the oil window in the lower Miocene. Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower middle to upper Miocene reservoirs. Basin modeling that incorporated an analysis of the petroleum system in the Abu Madi/El Qar'a field can help guide the next exploration phase, while oil exploration is now focused along post-late Miocene migration paths. These results suggest that deeper sections may have reservoirs charged with significant unrealized gas potential.

scholarly journals Structural traps and seals for expanding CO2 storage in the northern Horda Platform, North Sea

2021 ◽  
Author(s):  
Johnathon Osmond ◽  
Mark Mulrooney ◽  
Nora Holden ◽  
Elin Skurtveit ◽  
Jan Inge Faleide ◽  
...  
Keyword(s):  
North Sea ◽  
Co2 Storage ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Climate Mitigation ◽  
Fault Rock ◽  
Entire Study ◽  
The North ◽  
Major Fault ◽  
The North Sea

The maturation of geological CCS along the Norwegian Continental Shelf is ongoing in the Norwegian North Sea, however, more storage sites are needed to reach climate mitigation goals by 2050. In order to augment the Aurora site and expand CO2 storage in the northern Horda Platform, regional traps and seals must be assessed to better understand the area’s potential. Here, we leverage wellbore and seismic data to map storage aquifers, identify structural traps, and assess possible top and fault seals associated with Lower and Upper Jurassic storage complexes in four major fault blocks. With respect to trap and seal, our results maintain that both prospective intervals represent viable CO2 storage options in various locations of each fault block. Mapping, modeling, and formation pressure analyses indicate that top seals are present across the entire study area, and are sufficiently thick over the majority of structural traps. Across-fault juxtaposition seals are abundant, but dominate the Upper Jurassic storage complexes. Lower Jurassic aquifers, however, are often upthrown against Upper Jurassic aquifers, but apparent across fault pressure differentials and moderate to high shale gouge ratio values correlate, suggesting fault rock membrane seal presence. Zones of aquifer self-juxtaposition, however, are likely areas of poor seal along faults. Overall, our results provide added support that the northern Horda Platform represents a promising location for expanding CO2 storage in the North Sea, carrying the potential to become a future injection hub for CCS in northern Europe.

AN EARLY CRETACEOUS SOURCE ROCK IN THE KENDREW TERRACE, DAMPIER SUB-BASIN?

1996 ◽  
Vol 36 (1) ◽  
pp. 477 ◽  
Author(s):  
S. Ryan-Grigor ◽  
C. M. Griffiths
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Early Cretaceous ◽  
Late Jurassic ◽  
Large Scale ◽  
Free Water ◽  
Organic Content ◽  
Source Rocks ◽  
The North ◽  
Northern North Sea

The Early to Middle Cretaceous is characterised worldwide by widespread distribution of dark shales with high gamma ray readings and high organic contents defined as dark coloured mudrocks having the sedimentary, palaeoecological and geochemical characteristics associated with deposition under oxygen-deficient or oxygen-free bottom waters. Factors that contributed to the formation of the Early to Middle Cretaceous 'hot shales' are: rising sea-level, a warm equable climate which promoted water stratification, and large scale palaeogeographic features that restrict free water mixing. In the northern North Sea, the main source rock is the Late Jurassic to Early Cretaceous Kimmeridge Clay/Draupne Formation 'hot shale' which occurs within the Viking Graben, a large fault-bounded graben, in a marine environment with restricted bottom circulation and often anaerobic conditions. Opening of the basin during a major trans-gressive event resulted in flushing, and deposition of normal open marine shales above the 'hot shales'. The Late Callovian to Berriasian sediments in the Dampier Sub-basin are considered to have been deposited in restricted marine conditions below a stratified water column, in a deep narrow bay. Late Jurassic to Early Cretaceous marine sequences that have been cored on the North West Shelf are generally of moderate quality, compared to the high quality source rocks of the northern North Sea, but it should be noted that the cores are from wells on structural highs. The 'hot shales' are not very organic-rich in the northern Dampier Sub-basin and are not yet within the oil window, however seismic data show a possible reduction in velocity to the southwest in the Kendrew Terrace, suggesting that further south in the basin the shales may be within the oil window and may also be richer in organic content. In this case, they may be productive source rocks, analogous to the main source rock of the North Sea.

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