Inventory of onshore petroleum seeps and stains in Greenland: a web-based GIS model

A new inventory on onshore petroleum seeps and stains in Greenland has been released by the Geological Survey of Denmark and Greenland as a web-based GIS model on the Greenland Mineral Resources Portal: Petroleum Seeps and Stains in Greenland. Knowledge on oil and gas seeps, oil stains and solid bitumen occurrences provides key information on mineral and petroleum systems, especially in frontier basins. As the understanding of recent and previous migrations of fluids and gases is important for both mineral and petroleum explorations in Greenland, this new inventory has been developed to facilitate exploration and new activities. The classification includes the following types of occurrences: (1) oil seeps, (2) gas seeps, (3) mud diapirs, pingos and gas-rich springs, (4) oil stains in volcanics, carbonates and sandstones, (5) solid macroscopic bitumen and (6) fluid inclusions and other evidence of micro-seepage. The inventory comprises detailed information on localities, coordinates and sample numbers. It also includes descriptions of features and geology, references to data, reports and publications. All information is summarised in either a mineral or petroleum systems context. Petroleum seeps and stains have been reported from most Palaeozoic, Mesozoic and Cenozoic basins in Greenland where they add important information on petroleum systems, especially distribution and facies variation of source rocks, petroleum generation and later migration, accumulation, remigration, uplift and degradation. The inventory is designed to be updated with additional localities and descriptions and new organic geochemical data. This paper provides a general overview of classification, nomenclature, organisation and content of the inventory. We introduce the regional distribution of petroleum seeps and stains in Greenland and general interpretations in the context of mineral and petroleum systems.

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Geochemistry and Genesis of Oil and Gas Seeps in the Junggar Basin, NW China: Implications for Hybrid Petroleum Systems

Geofluids ◽

10.1155/2019/9732674 ◽

2019 ◽

Vol 2019 ◽

pp. 1-26

Author(s):

Jingkun Zhang ◽

Jian Cao ◽

Yan Wang ◽

Jun Li ◽

Guang Hu ◽

...

Keyword(s):

Oil And Gas ◽

Junggar Basin ◽

Source Rocks ◽

Middle Segment ◽

Nw China ◽

Southern Basin ◽

Petroleum Systems ◽

Oil Seeps ◽

Western Segment ◽

Gas Seeps

The Junggar Basin of NW China is representative in containing oil and gas seeps worldwide as there are a wide variety of oil and gas seeps over a large area. However, the genesis of these seeps remains poorly known, limiting the understanding of their implications for petroluem geology and hydrocarbon exploration. Here, we investigate 26 samples of oil and gas seeps from nine outcrops within five areas along the margins of the Junggar Basin to determine the geochemical characteristics of the hydrocarbons, constrain their genesis, and discuss future exploration strategies. Results indicate one type of gas seeps and five types of oil seeps. The gas seeps are derived from low-maturity Jurassic source rocks and occur in the Wusu and Dushanzi areas in the western segment of the southern basin. Type 1 oil seeps, sourced from lower Permian rocks (P1f), occur on the northwestern margin. Type 2 oil seeps, derived from middle Permian source rocks (P2l/P2p), occur on the eastern segment of the southern margin and eastern margin of the Junggar Basin. Type 3 oil seeps, with Jurassic source rocks, occur in the Qigu area in the middle segment of the southern basin. Type 4 oil seeps, with Cretaceous source rocks, occur in the Anjihai and Huoerguosi areas within the middle segment of the southern basin. Type 5 oil seeps mainly have Paleogene source rocks with a minor contribution from Jurassic rocks and occur in the Wusu and Dushanzi areas in the western segment of the southern basin with the single-type gas seeps. These results indicate the presence of lacustrine hybrid petroleum systems within the Junggar Basin with complex oil and gas sources and migration-accumulation. Six potential areas along the basin margin were proposed for exploration in the future.

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Research for the Upstream Petroleum Sector: The Crown Research Institute Concept

Energy Exploration & Exploitation ◽

10.1177/0144598795013002-313 ◽

1995 ◽

Vol 13 (2-3) ◽

pp. 245-252

Author(s):

J M Beggs

Keyword(s):

New Zealand ◽

Oil And Gas ◽

Sedimentary Basins ◽

Source Rocks ◽

Publicly Funded ◽

Petroleum Systems ◽

Oil And Gas Resources ◽

Petroleum Sector ◽

Geological Sciences ◽

Research Institute

New Zealand's scientific institutions have been restructured so as to be more responsive to the needs of the economy. Exploration for and development of oil and gas resources depend heavily on the geological sciences. In New Zealand, these activities are favoured by a comprehensive, open-file database of the results of previous work, and by a historically publicly funded, in-depth knowledge base of the extensive sedimentary basins. This expertise is now only partially funded by government research contracts, and increasingly undertakes contract work in a range of scientific services to the upstream petroleum sector, both in New Zealand and overseas. By aligning government-funded research programmes with the industry's knowledge needs, there is maximum advantage in improving the understanding of the occurrence of oil and gas resources. A Crown Research Institute can serve as an interface between advances in fundamental geological sciences, and the practical needs of the industry. Current publicly funded programmes of the Institute of Geological and Nuclear Sciences include a series of regional basin studies, nearing completion; and multi-disciplinary team studies related to the various elements of the petroleum systems of New Zealand: source rocks and their maturation, migration and entrapment as a function of basin structure and tectonics, and the distribution and configuration of reservoir systems.

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Anabar-Lena Composite Tectono-Sedimentary Element, Northern East Siberia

Geological Society London Memoirs ◽

10.1144/m57-2021-29 ◽

2021 ◽

pp. M57-2021-29

Author(s):

A.K. Khudoley ◽

S.V. Frolov ◽

G.G. Akhmanov ◽

E.A. Bakay ◽

S.S. Drachev ◽

...

Keyword(s):

Late Cretaceous ◽

Oil And Gas ◽

Foreland Basin ◽

Early Carboniferous ◽

Passive Margin ◽

Source Rocks ◽

East Siberia ◽

Lena River ◽

Petroleum Systems ◽

Intracratonic Basin

AbstractAnabar-Lena Composite Tectono-Sedimentary Element (AL CTSE) is located in the northern East Siberia extending for c. 700 km along the Laptev Sea coast between the Khatanga Bay and Lena River delta. AL CTSE consists of rocks from Mesoproterozoic to Late Cretaceous in age with total thickness reaching 14 km. It evolved through the following tectonic settings: (1) Meso-Early Neoproterozoic intracratonic basin, (2) Ediacaran - Early Devonian passive margin, (3) Middle Devonian - Early Carboniferous rift, (4) late Early Carboniferous - latest Jurassic passive margin, (5) Permian foreland basin, (6) Triassic to Jurassic continental platform basin and (7) latest Jurassic - earliest Late Cretaceous foreland basin. Proterozoic and lower-middle Paleozoic successions are composed mainly by carbonate rocks while siliciclastic rocks dominate upper Paleozoic and Mesozoic sections. Several petroleum systems are assumed in the AL CTSE. Permian source rocks and Triassic sandstone reservoirs are the most important play elements. Presence of several mature source rock units and abundant oil- and gas-shows (both in wells and in outcrops), including a giant Olenek Bitumen Field, suggest that further exploration in this area may result in economic discoveries.

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COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

The APPEA Journal ◽

10.1071/aj02006 ◽

2003 ◽

Vol 43 (1) ◽

pp. 117 ◽

Cited By ~ 18

Author(s):

C.J. Boreham ◽

J.E. Blevin ◽

A.P. Radlinski ◽

K.R. Trigg

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Middle Eocene ◽

Vitrinite Reflectance ◽

Mineral Resources ◽

Sedimentary Basins ◽

Source Rocks ◽

Gas Generation ◽

Australian Context ◽

Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

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THE STRUCTURAL DEVELOPMENT AND HYDROCARBON POTENTIAL OF PALAEOZOIC SOURCE ROCKS IN THE ADAVALE BASIN REGION

The APPEA Journal ◽

10.1071/aj83031 ◽

1984 ◽

Vol 24 (1) ◽

pp. 393 ◽

Cited By ~ 2

Author(s):

V. L. Passmore ◽

M. J. Sexton

Keyword(s):

Middle Devonian ◽

Oil And Gas ◽

Structural Features ◽

Source Rocks ◽

Geochemical Data ◽

Mature Stage ◽

Hydrocarbon Generation ◽

Structural Development ◽

Seismic Reflection Data ◽

Basin Region

The Adavale Basin of southwestern Queensland consists of a main depression and several isolated synclinal extensions, traditionally referred to as troughs. The depressions and troughs are erosional remnants of a once more extensive Devonian depositional basin, and are now completely buried by sediments of the overlying Cooper, Galilee and Eromanga Basins. Geophysical and drilling investigations undertaken since 1959 are the only source of information on the Adavale Basin. A single sub-economic discovery of dry gas at Gilmore and a few shows of oil and gas are the only hydrocarbons located in the basin to date.In 1980, the Bureau of Mineral Resources in cooperation with the Geological Survey of Queensland commenced a major, multidisciplinary investigation of the basins in southwestern Queensland. Four long (> 200 km) seismic lines from this study over the Adavale Basin region and geochemical data from 20 wells were used to interpret the Adavale Basin's development and its present hydrocarbon potential.The new seismic reflection data allow the well-explored main depression to be correlated with the detached troughs, some of which have little or no well information. The BMR seismic data show that these troughs were previously part of one large depositional basin in the Devonian, the depocentre of which lay east of a north-trending hingeline. Structural features and Devonian depositional limits and patterns have been modified from earlier interpretations as a result of the new seismic coverage. The maximum sediment thickness is re-interpreted to be 8500 m, considerably thicker than previous interpretation.recognised. The first one, a diachronous Middle Devonian unconformity, is the most extensive, and reflects the mobility of the basement during the basin's early history. The second unconformity within the Late Devonian Buckabie Formation reveals that there were two phases of deformation of the basin sediments.The geochemical results reported in this study show that most of the Adavale Basin sediments have very low concentrations of organic carbon and hydrocarbon fractions. Maturity profiles indicate that the best source rocks of the basin are now in the mature stage for hydrocarbon generation. However, at Gilmore and in the Cooladdi Trough, they have reached the dry gas stage. The maturity data provide additional evidence for the marked break in deposition and significant erosion during the Middle Devonian recognised on the seismic records, and extend the limits of this sedimentary break into the northern part of the main depression.Hydrocarbon potential of the Adavale Basin is fair to poor. In the eastern part of the basin, where most of the data are available, the prospects are better for gas than oil. Oil prospectivity may be improved in any exinite-rich areas that exist farther west, where palaeo-temperatures were lower.

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PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

The APPEA Journal ◽

10.1071/aj99002 ◽

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.

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Geochemical characterization of hydrocarbon source rocks of the Triassic-Jurassic time interval in the Mandawa basin, southern Tanzania: Implications for petroleum generation potential

South African Journal of Geology ◽

10.25131/sajg.123.0037 ◽

2020 ◽

Vol 123 (4) ◽

pp. 587-596

Author(s):

A. Emanuel ◽

C.H. Kasanzu ◽

M. Kagya

Keyword(s):

Source Rocks ◽

Geochemical Data ◽

Time Interval ◽

Type I ◽

Hydrocarbon Generation ◽

Type Ii ◽

Geochemical Characterization ◽

Type Iii ◽

Petroleum Generation

Abstract Triassic to mid-Jurassic core samples of the Mandawa basin, southern Tanzania (western coast of the Indian Ocean), were geochemically analyzed in order to constrain source rock potentials and petroleum generation prospects of different stratigraphic formations within the coastal basin complex. The samples were collected from the Mihambia, Mbuo and Nondwa Formations in the basin. Geochemical characterization of source rocks intersected in exploration wells drilled between 503 to 4042 m below surface yielded highly variable organic matter contents (TOC) rated between fair and very good potential source rocks (0.5 to 8.7 wt%; mean ca. 2.3 wt%). Based on bulk geochemical data obtained in this study, the Mandawa source rocks are mainly Type I, Type II, Type III, mixed Types II/III and Type IV kerogens, with a predominance of Type II, Type III and mixed Type II/III. Based on pyrolysis data (Tmax 417 to 473oC; PI = 0.02 to 0.47; highly variable HI = 13 to 1 000 mg/gTOC; OI = 16 to 225 mg/g; and VR values of between 0.24 to 0.95% Ro) we suggest that the Triassic Mbuo Formation and possibly the mid-Jurassic Mihambia Formation have a higher potential for hydrocarbon generation than the Nondwa Formation as they are relatively thermally mature.

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Petroleum systems of the Bass Basin: a 3D modelling perspective

The APPEA Journal ◽

10.1071/aj09030 ◽

2010 ◽

Vol 50 (1) ◽

pp. 511 ◽

Cited By ~ 3

Author(s):

Natt Arian ◽

Peter Tingate ◽

Richard Hillis ◽

Geoff O'Brien

Keyword(s):

Middle Eastern ◽

Source Rocks ◽

Petroleum Systems ◽

Systems Model ◽

Basin Scale ◽

Exploration Risk ◽

New Locations ◽

Petroleum Generation ◽

And Migration ◽

Hydrocarbon Expulsion

Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin; however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal. The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited; however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations. The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources; however, Miocene reactivation is a major exploration risk in this area.

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

The APPEA Journal ◽

10.1071/aj06007 ◽

2007 ◽

Vol 47 (1) ◽

pp. 127 ◽

Cited By ~ 1

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.

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

10.2118/afrc-2552889-ms ◽

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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