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

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.

scholarly journals 2-D Basin modeling study of petroleum systems in the Levantine Basin, Eastern Mediterranean

GeoArabia ◽  
2011 ◽  
Vol 16 (2) ◽  
pp. 17-42
Author(s):  
Lisa Marlow ◽  
Kristijan Kornpihl ◽  
Christopher G. St. C. Kendall
Keyword(s):  
Oil And Gas ◽  
Nile Delta ◽  
Eastern Mediterranean ◽  
System Modeling ◽  
Passive Margin ◽  
Source Rocks ◽  
Petroleum Systems ◽  
Levantine Basin ◽  
Potential Source Rock ◽  
Potential Reservoir

ABSTRACT The Levantine Basin has proven hydrocarbons, yet it is still a frontier basin. There have been significant oil and gas discoveries offshore the Nile Delta, e.g. several Pliocene gas plays and the Mango Well with ca. 10,000 bbls/day in Lower Cretaceous rocks and recently, Noble Energy discovered two gas “giants” (> 5 TCF and one estimated at 16 TFC) one of which is in a pre-Messinian strata in ca. 1,700 m (5,577 ft) water depth. Regional two-dimensional (2-D) petroleum system modeling suggests that source rocks generated hydrocarbons throughout the basin. This paper provides insight into the petroleum systems of the Levantine Basin using well and 2-D seismic data interpretations and PetroMod2D. Tectonics followed the general progression of the opening and closing of the Neo-Tethys Ocean: rift-extension, passive margin, and compression. The stratal package is up to 15 km thick and consists of mixed siliciclastic-carbonate-evaporite facies. Five potential source rock intervals (Triassic – Paleocene) are suggested. Kerogen in the older source rocks is fully transformed, whereas the younger source rocks are less mature. There are several potential reservoir and seal rocks. The model suggests that oil and gas accumulations exist in both structural and stratigraphic traps throughout the basin.

The Yenisei-Khatanga Composite Tectono-Sedimentary Element, Northern Siberia

2021 ◽  
pp. M57-2021-15
Author(s):  
E. V. Deev ◽  
G. G. Shemin ◽  
V. A. Vernikovsky ◽  
O. I. Bostrikov ◽  
P. A. Glazyrin ◽  
...  
Keyword(s):  
Siberian Craton ◽  
Middle Triassic ◽  
Foreland Basin ◽  
Early Carboniferous ◽  
Source Rocks ◽  
Total Thickness ◽  
Petroleum Potential ◽  
Early Paleocene ◽  
Middle Carboniferous ◽  
Severnaya Zemlya

AbstractThe Yenisei-Khatanga Composite Tectono-Sedimentary Element (YKh CTSE) is located between the Siberian Craton and the Taimyr-Severnaya Zemlya fold-and-thrust belt. The total thickness of the Mesoproterozoic-Cenozoic sediments of YKh CTSE reaches 20 to 25 km. They are divided into four tectono-sedimentary elements (TSE): (i) Mesoproterozoic-early Carboniferous Siberian Craton continental margin, (ii) middle Carboniferous-Middle Triassic syn-orogenic Taimyr foreland basin, (iii) late Permian-Early Triassic syn-rift, and (iv) Triassic-Early Paleocene post-rift. The last one is the most important in terms of its petroleum potential and is the most drilled part of the CTSE. Its thickness accounts for half of the total thickness of YKh CTSE. The margins of the post-rift TSE and the inner system of inversion swells and adjacent troughs and depressions were shaped by three tectonic events: (i) middle Carboniferous-Middle Triassic Taimyr orogeny, (ii) Late Jurassic-Early Cretaceous Verkhoyansk orogeny, (iii) Late Cenozoic uplift. These processes led to more intense migration of hydrocarbons, the trap formation and their infill with hydrocarbons. Triassic, Jurassic, and Lower Cretaceous source rocks are mostly gas-prone, and among 20 discovered fields in Jurassic and Cretaceous plays, 17 are gas or mixed-type fields.

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

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.

GEOLOGY AND HYDROCARBON POTENTIAL OF THE SOUTHERN GEORGINA BASIN, AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 139 ◽  
Author(s):  
G.J. Ambrose ◽  
P.D. Kruse ◽  
P.E. Putnam
Keyword(s):  
Early Carboniferous ◽  
Source Rocks ◽  
Peak Oil ◽  
Middle Cambrian ◽  
Late Cambrian ◽  
Oil Generation ◽  
World Class ◽  
Lower Palaeozoic ◽  
Southwestern Margin ◽  
Intracratonic Basin

The Georgina Basin is an intracratonic basin on the central-northern Australian craton. Its southern portion includes a highly prospective Middle Cambrian petroleum system which remains largely unexplored. A plethora of stratigraphic names plagued previous exploration but the lithostratigraphy has now been rationalised using previously unpublished electric-log correlations and seismic and core data.Neoproterozoic and Lower Palaeozoic sedimentary rocks of the southern portion of the basin cover an area of 100,000 km2 and thicken into two main depocentres, the Toko and Dulcie Synclines. In and between these depocentres, a Middle Cambrian carbonate succession comprising Thorntonia Limestone and Arthur Creek Formation provides a prospective reservoir-source/seal couplet extending over 80,000 km2. The lower Arthur Creek Formation includes world class microbial source rocks recording total organic carbon (TOC) values of up to 16% and hydrocarbon yields up to 50 kg/tonne. This blanket source/seal unconformably overlies sheetlike, platform dolostone of the Thorntonia Limestone which provides the prime target reservoir. Intra- Arthur Creek high-permeability grainstone shoals are important secondary targets.In the Toko Syncline, Middle Cambrian source rocks entered the oil window during the Ordovician, corresponding to major sediment loading at this time. The gas window was reached prior to structuring associated with the Middle Devonian-Early Carboniferous Alice Springs Orogeny, and source rocks today lie in the dry gas window. In contrast, high-temperature basement granites have resulted in overmaturity of the Arthur Creek Formation in the Dulcie Syncline area. On platform areas adjacent to both these depocentres source rocks reached peak oil generation shortly after the Alice Springs Orogeny; numerous structural leads have been identified in these areas. In addition, an important stratigraphic play occurs in the Late Cambrian Arrinthrunga Formation (Hagen Member) on the southwestern margin of the basin. Key elements of the play are the pinchout of porous oil-stained, vuggy dolostone onto basement where top seal is provided by massive anhydrite while underlying Arthur Creek Formation shale provides a potential source.

THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 405 ◽  
Author(s):  
C.W. Luxton ◽  
S. T. Horan ◽  
D.L. Pickavance ◽  
M.S. Durham.
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Production Test ◽  
Water Contact ◽  
Excellent Quality ◽  
Fault Block ◽  
Well Location ◽  
Gas Fields

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

New play type, southern Bonaparte Basin-Petrel Sub-basin—WA-442-P and NT/P81 exploration permits

2012 ◽  
Vol 52 (1) ◽  
pp. 525
Author(s):  
Margaret Hildick-Pytte
Keyword(s):  
Seismic Data ◽  
Early Carboniferous ◽  
Oil Fields ◽  
Source Rocks ◽  
Lower Carboniferous ◽  
Petroleum Systems ◽  
Seismic Data Acquisition ◽  
Early Palaeozoic ◽  
Hydrocarbon Charge ◽  
3D Seismic Data

Recent investigation, including mapping re-processed seismic data, suggests there is deeper hydrocarbon potential in the WA-442-P and NT/P81 exploration permits beneath the Early Carboniferous Tanmurra Formation horizon. Earlier interpretation of the area showed tilted fault blocks commonly thought of as economic basement in the vicinity of the Turtle and Barnett oil fields and extending to the northwest to connect with the Berkley Platform. The deep-gas play type is structural and is believed to be two nested three-way dip anticlines developed against a large bounding fault to the northeast, with axial trends northwest to southeast, and axial plane curving towards the northeast for the deeper structure. This play type is believed to be associated with structural compression and movement along the master fault with incremental re-activation most recently during the Cainozoic as recorded in overlying sediments. The Nova Structure and the deeper Super Nova structure have closures of about 450 and 550 km2, respectively. The sediments beneath the Nova horizon are believed to be of Devonian Frasnian-Famennian age but have not been drilled offshore in the Southern Bonaparte Basin (Petrel Sub-basin). Earlier work suggests that there are two petroleum systems present in the southern Bonaparte Basin, a Larapintine source from Early Palaeozoic Devonian to Lower Carboniferous source rocks, and a transitional Larapintine/Gondwana system sourced from Lower Carboniferous to Permian source rocks. Hydrocarbon charge for the structures is most likely from the Larapintine source rock intervals or yet to be identified older intervals associated with the salt deposition during the Ordovician and Silurian. Independent estimates place close to 7 TCF (trillion cubic feet) of gas in the Nova Structure. New 3D seismic data acquisition is planned over the structures to better define the geology and ultimately delineate well locations.

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.

A Cretaceous Neo-Tethyan carbonate margin in Argolis, southern Greece

1990 ◽  
Vol 127 (4) ◽  
pp. 299-308 ◽  
Author(s):  
Peter D. Clift ◽  
Alastair H. F. Robertson
Keyword(s):  
Late Cretaceous ◽  
Foreland Basin ◽  
Ocean Basin ◽  
Passive Margin ◽  
Accretionary Complex ◽  
Early Tertiary ◽  
Thrust Sheets ◽  
Pelagonian Zone ◽  
Structural Levels ◽  
Southern Greece

AbstractThe Argolis Peninsula, southern Greece, is believed to form part of a Pelagonian microcontinent located between two oceanic basins, the Pindos to the west and theVardar to the east, in Triassic to Tertiary time. In eastern Argolis, two important units are exposed: (i) the Ermioni Limestones cropping out in the southwest; (ii) the Poros Formation, observed on an offshore island in the northeast, and on the adjacent mainland. Both these units comprise late Cretaceous (Aptian-Maastrichtian) pelagic limestones, calciturbidites, lenticular matrix- and clast-supported limestone conglomerates and slump sheets. However, the Poros Formation is distinguished from the Ermioni Limestones by the presence of bituminous micritic limestones and an increasing proportion of shale up sequence. These successions are deep-water slope carbonates that once formed the southeast-facing passive margin of the Pelagonian platform (Akros Limestone). Beyond this lay a late Cretaceous ocean basin in the Vardar Zone. This ocean was consumed in an easterly-dipping subduction zone in latest Cretaceous (?) to early Tertiary time, giving rise to an accretionary complex (Ermioni Complex). During early Tertiary (Palaeocene-Eocene) time the passive continental margin (Pelagonian Zone) collided with the trench and accretionary complex to the east. As the suture tightened, former lower-slope carbonates (Ermioni Limestones) were accreted to the base of the over-riding thrust sheets and emplaced onto the platform. Farther west, bituminous upper slope carbonates (Poros Formation) flexurally subsided and passed transitionally upwards into calcareous flysch and olistostromes in a foreland basin. These sediments were then overridden by the emplacing thrust stack and themselves underplated. Late-stage high-angle faulting then disrupted the tectonostratigraphy, in places juxtaposing relatively high and low structural levels of the complex.

scholarly journals The hidden sedimentary basin underneath the Quaternary volcanic unit in Bogor and Kendeng area

2021 ◽  
Vol 47 (2) ◽  
pp. 25-47
Author(s):  
Erlangga Septama ◽  
C. Prasetyadi ◽  
A Abdurrokhim ◽  
T. Setiawan ◽  
P.D. Wardaya ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Sediment Supply ◽  
Passive Margin ◽  
Magnetic Data ◽  
Rock Samples ◽  
Petroleum Systems ◽  
The North ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data ◽  
East West

The Java Island is an active volcanic arc that experiences several volcanism episodes, which gradually changes from South to North from the Late Oligocene to Pleistocene, following the subduction of the Australian plates underneath the Eurasian plates. During the Eocene, the southern and northern part of Java was connected as one passive margin system with the sediment supply mainly comes from Sundaland in the north.  The compressional tectonics creates a flexural margin and a deep depression in the central axis of Java Island and acts as an ultimate deep-sea depocenter in the Neogene period. In contrast to the neighboring Northwest and Northeast Java Basins in the Northern edges of Java Island, the basin configuration in the East-West trending depression in median ranges of Java (from Bogor to Kendeng Troughs) are visually undetected by seismic due to the immense Quaternary volcanic eruption covers.Five focused window areas are selected for this study. A total of 1,893 Km sections, 584 rock samples, 1569 gravity and magnetic data, and 29 geochemical samples (rocks, oil, and gas samples) were acquired during the study. Geological fieldwork was focused on the stratigraphic unit composition and the observable features of deformation products from the outcrops. Due to the Paleogene deposit exposure scarcity in the Central-East Java area, the rock samples were also collected from the mud volcano ejected materials in the Sangiran Dome.The distinct subsurface configuration differences between Bogor and Kendeng Troughs are mainly in the tectonic basement involvement and the effect of the shortening on the formerly rift basin. Both Bogor and Kendeng Troughs are active petroleum systems that generate type II /III Kerogen typical of reduction zone organic material derived from transition to the shallow marine environment. The result suggests that these basins are secular from the neighboring basins with a native petroleum system specific to the palaeogeographical condition during the Paleogene to Neogene periods where the North Java systems (e.g., Northwest and Northeast Java Basin) was characterized by oxidized terrigenous type III Kerogen.

Tectonostratigraphic development and hydrocarbon reservoir quality on a convergent margin: East Coast, North Island, New Zealand

2009 ◽  
Vol 49 (2) ◽  
pp. 600
Author(s):  
Brad Field ◽  
Jan Baur ◽  
Kyle Bland ◽  
Greg Browne ◽  
Angela Griffin ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
East Coast ◽  
Fractured Reservoirs ◽  
Hydrocarbon Exploration ◽  
Passive Margin ◽  
Source Rocks ◽  
Reservoir Quality ◽  
High Porosity ◽  
Hydrocarbon Reservoir ◽  
Reservoir Potential

Hydrocarbon exploration on the East Coast of the North Island has not yet yielded significant commercial reserves, even though the elements of a working petroleum system are all present (Field et al, 1997). Exploration has focussed on the shallow, Neogene part of the succession, built up during plate margin convergence over the last ∼24 million years. Convergent margins are generally characterised by low-total organic carbon (TOC) source rocks and poor clastic reservoir quality due to poor sorting and labile grains. However, the obliquely-convergent Hikurangi subduction margin of the East Coast has high TOC source rocks that pre-date the subduction phase, and its reservoir potential, though variable, has several aspects in its favour, namely: deep-water rocks of high porosity and permeability; preservation of pore space by overpressure; the presence of fractured reservoirs and hybrid reservoirs, where low clastic permeability is enhanced by fractures. The East Coast North Island is a Neogene oblique subduction margin, with Neogene shelf and slope basins that developed on Late Cretaceous-Paleogene passive margin marine successions. The main hydrocarbon source rocks are Late Cretaceous and Paleocene and the main reservoir potential is in the Neogene (Field et al, 2005). Miocene mudstones with good seal potential are common, as is significant over-pressuring. Neogene deformation controlled basin development and accommodation space and strongly-influenced lateral facies development and fractured reservoirs. Early to Middle Miocene thrusting was followed by later Neogene extension (e.g. Barnes et al 2002), with a return to thrusting in the Pliocene. Local wells have flow-tested gas shows.

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