STRATIGRAPHY OF THE SOUTHERN SAHUL PLATFORM

1998 ◽  
Vol 38 (1) ◽  
pp. 115 ◽  
Author(s):  
V.R. Labutis ◽  
A.D. Ruddock ◽  
A.P. C alcraft
Keyword(s):  
Middle Jurassic ◽  
Oil And Gas ◽  
Depositional Environments ◽  
Source Rocks ◽  
Depositional Sequences ◽  
Sequence Stratigraphic ◽  
Sag Basin ◽  
Breakup Unconformity ◽  
East West ◽  
Reservoir Facies

This study of the southern Sahul Platform area in the Zone of Cooperation is based on the identification of depositional sequences, their distribution and relationship to structuring events in order to predict the locations of favourable combinations of source, seal and reservoir facies with increased confidence. A sequence stratigraphic approach integrating well logs, palynology and seismic data was used to identify and map significant seismic horizons such as the Aptian and Tithonian unconformities.Early to Middle Jurassic sediments were deposited in a broad, northeast-southwest oriented sag basin with a northeastward sediment transport direction. Depositional environments range from non-marine to marginal marine in the Plover Formation to the shallow marine sediments of the Elang Formation. The Elang Formation, comprising two depositional sequences, represents the last of the sediments deposited before the Breakup Unconformity. These formations comprise the dominant reservoir facies, containing a number of oil and gas discoveries. Porosity degradation occurs in Jurassic reservoirs below 3,360 m.The Callovian Breakup Unconformity resulted in the initiation of the narrow, confined depocentres of the Sahul Syncline, Malita Graben and a series of east-west troughs. The Sahul Platform and Londonderry High comprise the flanks of these depocentres but were originally located within the depocentre of the Early to Middle Jurassic sag basin. The Flamingo Syncline is a younger feature developed in the Albian.Late Jurassic and Early Cretaceous sediments are confined mainly to the Sahul Syncline and Malita Graben and are absent or represented by thin, condensed sections on the flanking highs. The condensed sections on horst blocks are a result of sediment bypass rather than considerable erosion. Reservoir facies of Tithonian-Berriasian age are interpreted to occur within east-west troughs constituting another reservoir section apart from the Bathonian-Callovian sediments. Wells distant from the Sahul Syncline and Malita Graben, have encountered hydrocarbons, indicating that the area contains mature source rocks, capable of charging traps away from the immediate vicinity of the depocentres.

THE GWYDION DISCOVERY: A NEW PLAY FAIRWAY IN THE BROWSE BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 87 ◽  
Author(s):  
T. B. Spry ◽  
I. Ward
Keyword(s):  
Oil And Gas ◽  
High Amplitude ◽  
Source Rocks ◽  
Shelf Area ◽  
Sequence Stratigraphic ◽  
Eastern Margin ◽  
Migration Pathway ◽  
Island Group ◽  
Basement High ◽  
Gas Bearing

The Gwydion-1 oil and gas discovery well is located in exploration permit WA-239-P on the sparsely explored Yampi Shelf area of the Browse Basin. The Gwydion feature was first recognised as a series of stacked seismic amplitude anomalies, which were interpreted to represent hydrocarbon-bearing Barremian to Albian age shallow marine sandstones draped over a prominent basement high. Amplitude versus offset analysis and modelling supported this interpretation.Gwydion-1 was spudded on 4th June, 1995, and discovered three gas bearing zones and one oil and gas bearing zone. The lowermost zone is Barremian to Hauterivian in age and consists of 12.6 m of net gas-filled glauconitic sand overlying a 9.5 m net oil-filled quartz sand. The three overlying hydrocarbon zones consist of glauconitic reservoirs of Barremian to Albian age.The play fairway for Gwydion-style traps has been named as the Echuca/Swan-Bathurst Island Group/Shelfal Play Fairway. It comprises mature Swan Group and Echuca Shoals Formation source rocks, and Bathurst Island Group reservoirs and seals. The limits of the play fairway on the shelf are controlled by the existence of topographic relief in the underlying basement metasediments. Migration pathway analysis suggests that the eastern margin of the Browse Basin is favourably situated to receive charge from the mature source rocks within the basin.The dominant northwesterly dip of the strata on the Yampi Shelf limits the potential for structural traps. Accordingly, a thorough understanding of the sequence stratigraphic architecture of the succession is necessary in order to generate the stratigraphic play concepts which hold the bulk of the prospectivity in the area.Gwydion-1 was plugged and abandoned as an uneconomic oil and gas discovery. It was, however, significant as it validated a new play type and generated renewed interest in the eastern margin of the Browse Basin for the first time since the mid 1970s; an area previously thought to be too shallow, too far from mature source and lacking reliable seal.

Study on Hydrocarbon Source Rocks with Accumulation Characteristics Research of Camck-Aral Sea

2013 ◽  
Vol 703 ◽  
pp. 139-142
Author(s):  
Hui Ting Hu ◽  
Hai Tao Xue ◽  
Xiang Qi Kong ◽  
Hong Peng Yao
Keyword(s):  
Middle Jurassic ◽  
Oil And Gas ◽  
Source Rocks ◽  
Aral Sea ◽  
Maturity Stage ◽  
Hydrocarbon Source Rock ◽  
Oil And Gas Exploration ◽  
Hydrocarbon Source Rocks ◽  
The Matrix ◽  
Reservoir Conditions

Camck-Aral sea is one of the important China's developing overseas oil and gas exploration blocks. But conditioned by the degree of exploration, the hydrocarbon source rocks quality and resource potential of this block are not clear. Therefore, in this study, we analyzed the regional geological survey, hydrocarbon source rock condition and reservoir conditions. The results indicated that: The middle Jurassic formation in Camck-Aral sea block has a texture of interbeded sandstones and mudstones. Middle Jurassic hydrocarbon source rocks in Camck-Aral sea block is high in the abundance of organic matter,of which the matrix belongs to the type II2, and it has reached the maturity stage. This may mean that the study area should be based primarily on natural gas exploration.

scholarly journals Depositional Environments and Geochemical Assessments of the Bende Ameki Formation Potential as Petroleum Source Rocks in the Ogbunike Quarry, South-Eastern Nigeria

2018 ◽  
Vol 14 (27) ◽  
pp. 157 ◽  
Author(s):  
Olajubaje T. A. ◽  
Akande S.O. ◽  
Adeoye J. A. ◽  
Adekeye O. A. ◽  
Friedrich C.
Keyword(s):  
Niger Delta ◽  
Oil And Gas ◽  
Depositional Environments ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Rare Type ◽  
Southeastern Nigeria ◽  
Genetic Potential ◽  
Oxygenated Water

This paper focuses on investigating the paleoenvironments and hydrocarbon generation potentials of the outcropping Eocene Bende-Ameki Formation at Ogbunike quarry, Anambra Basin southeastern Nigeria, which is the Niger Delta Agbada Formation subsurface equivalent. The fine to coarse sandstones interbedded with parallel laminated grey, coaly shales, and bioturbated claystones were the dominant rock facies. The shales contain Ammobaculities, Ammontium, lenticulina, and Reophax benthic foraminifera of brackish to outer shelf environments. The rock sequence and biofacies associations indicate a fluvial, shoreface to delta environments. The marine and continental paleoenvironments are supported by the concentration and association of redox-sensitive trace elements such as vanadium and nickel of oxic to dysoxic paleoconditions. The twenty shales have a range of TOC from 0.39 - 8.81 wt% (mean 2.2 2 wt%), suggesting a good to very good source rocks. The organic richness is highest within the depth of 2 – 6 m across the quarry. Their genetic potential (S1+S2) ranges from 0.22 - 27.35 (mean 2.8 kgHC/ton) of rock, and hydrogen index from 26 to 292 mgHC/gTOC with a mean of 67.3 mgHC/gTOC. This, however, indicates dominance of Type III gas prone kerogen of terrestrial origin. The oxygenated water column characterized by the presence of benthonic scavengers may not preserve lipidenriched organic constituents of anoxic paleoenvironments which could account for the rare Type II oil and gas prone kerogen in the source rock. The thermal history inferred from the Tmax between 401°C - 424°C suggests that the source rocks are immature at the present stratigraphic level.

Arctic Alaska Basin, Hanna Trough, and Beaufortian Rifted Margin Composite Tectono-Sedimentary Elements

2021 ◽  
pp. M57-2018-26
Author(s):  
David W. Houseknecht
Keyword(s):  
Lower Cretaceous ◽  
Middle Jurassic ◽  
Source Rocks ◽  
The Arctic ◽  
North Slope ◽  
Growth Strata ◽  
Middle Mississippian ◽  
Arctic Alaska ◽  
Sag Basin ◽  
Rifted Margin

AbstractThe Arctic Alaska region includes three composite tectono-sedimentary elements (CTSEs): the (1) Arctic Alaska Basin (AAB), (2) Hanna Trough (HT), and (3) Beaufortian Rifted Margin (BRM) CTSEs. These CTSEs comprise Mississippian to Lower Cretaceous (Neocomian) strata beneath much of the Alaska North Slope, the Chukchi Sea and westernmost North Slope, and Beaufort Sea, respectively. These sedimentary successions rest on Devonian and older sedimentary and metasedimentary rocks, considered economic basement, and are overlain by Cretaceous to Cenozoic syn- and post-tectonic strata deposited in the foreland of the Chukotka and Brooks Range orogens and in the Amerasia Basin. (1) The Mississippian-Neocomian AAB CTSE includes two TSEs: (a) The Ellesmerian Platform TSE comprises mainly shelf strata of Mississippian to Middle Jurassic age and includes a relatively undeformed domain in the north and a fold-and-thrust domain in the south. (b) The Beaufortian Rift Shoulder TSE includes Middle Jurassic to Neocomian deposits related to rift-shoulder uplift. (2) The HT CTSE includes four TSEs: (a) The Ellesmerian Syn-Rift TSE comprises Late Devonian(?) to Middle Mississippian growth strata deposited in grabens and half grabens during intracontinental rifting. (b) The Ellesmerian-Beaufortian Sag-Basin TSE comprises Middle Mississippian to Upper Triassic strata deposited in a sag basin following cessation of rifting. (c) The Beaufortian Syn-Rift TSE comprises Jurassic to Neocomian graben-fill deposits related to rifting in the Amerasia and North Chukchi Basins. (d) The Beaufortian Rift-Shoulder TSE comprises Jurassic to Neocomian strata related to rifting and deposited outside rift basins. (3) The BRM CTSE includes two TSEs: (a) The Beaufortian Syn-Rift TSE comprises Middle Jurassic to Neocomian syn-rift strata deposited on attenuated continental crust associated with opening of the Amerasia Basin. (b) The Ellesmerian Platform TSE comprises mainly shelf strata of Mississippian to Middle Jurassic age that lie beneath Beaufortian syn-rift strata.The AAB, HT, and BRM CTSEs contain oil-prone source rocks in Triassic, Jurassic, and Cretaceous strata and proven reservoir rocks spanning Mississippian to Lower Cretaceous strata. A structurally high-standing area in the northern AAB CTSE, northern HT CTSE, and southernmost BRM CTSE lies in the oil window whereas all other areas lie in the gas window. Known hydrocarbon accumulations in the three CTSEs total more than 30 billion barrels of oil equivalent and yet-to-find estimates suggest a similar volume remains to be discovered.

scholarly journals Microfacies and sedimentary environments of the late Oligocene-early Miocene Qom Formation of the Gooreh Berenji region (Jandaq area, central Iran)

GeoArabia ◽  
2007 ◽  
Vol 12 (4) ◽  
pp. 41-60
Author(s):  
Shakeri Alireza ◽  
Douraghinejad Jalal ◽  
Moradpour Mehran
Keyword(s):  
Oil And Gas ◽  
Patch Reef ◽  
Depositional Environments ◽  
Central Iran ◽  
Source Rocks ◽  
Early Miocene ◽  
Petrographic Analysis ◽  
Late Oligocene ◽  
Qom Formation ◽  
Wide Range

ABSTRACT The late Oligocene-early Miocene Qom Formation in the Central Iran Basin contains oil and gas in the Alborz and Sarajeh fields. Organic geochemical analyses in previous studies indicated that the hydrocarbons migrated from deeper source rocks, likely of Jurassic age. In the Central Iran Basin, the Qom Formation is 1,200 m thick and is bounded by the Oligocene Lower Red Formation and the middle Miocene Upper Red Formation. In previous studies, the Qom Formation was divided into nine members designated from oldest to youngest: a, b, c to c4, d, e and f, of which “e” is 300 m thick and constitutes the main reservoir. Our study focused on a Qom section located in the Gooreh Berenji region of central Iran which is 294 m thick. The lower part of the formation was not deposited, and only the following four members of early Miocene age (Aquitanian and Burdigalian) were identified between the Lower and Upper Red formations: “c2”? (mainly greyish to greenish gypsiferous marls); “d” (thin- to thick-bedded anhydrite with intercalation of thin-bedded sandstone); “e” (argillaceous or sandy limestone); and “f” (fine-grained coral and bryozoan boundstone). In contrast to the Central Iran Basin, the “e” member in Gooreh Berenji is only 15 m thick and does not have a good reservoir potential. A detailed petrographic analysis of the Gooreh Berenji section resulted in the identification of 13 microfacies (MF) that were interpreted in terms of their depositional environments according to the following categories: MF1 (sabkha), MF2 (intertidal river channel), MF3 (lower intertidal), MF4 (peritidal), MF5 (supratidal), MF6 and MF7 (shallow restricted lagoon), MF8 and MF10 (proximal open-marine), MF9 (leeward lagoon), MF11 (shoal), MF12 (reef and patch reef formed within lagoon), and MF13 (open-marine). The Qom Formation constitutes a regional transgressive-regressive sequence that is bounded by two continental units (Lower and Upper Red formations). The transgression started from the south in the late Oligocene and by the early Miocene the sea covered all of central Iran. In the Gooreh Berenji area, carbonate deposition occurred on a shallow-marine ramp. The presence of a wide range of lagoonal facies indicates that reefal facies (“f”) developed in a narrow elongated strip away from the shoreline.

scholarly journals Geological and geochemical conditions for the formation of the oil composition in the deposits of the Permian and Jurassic oil and gas complexes in the Fukang depression (Junggar basin)

Georesursy ◽  
2021 ◽  
Vol 23 (2) ◽  
pp. 110-119
Author(s):  
Houqiang Yang ◽  
Elena V. Soboleva
Keyword(s):  
Isotopic Composition ◽  
Middle Jurassic ◽  
Oil And Gas ◽  
Carbon Isotopic Composition ◽  
Source Rocks ◽  
Middle Permian ◽  
Geochemical Conditions ◽  
Carbon Isotopic ◽  
Gas Source ◽  
Β Carotene

Within the eastern part of the Fukang depression, the main productive series are confined to the Permian and Jurassic oil and gas complexes (OGC), in which the Middle Permian and Lower-Middle Jurassic oil and gas source rocks (OGSRs) are distinguished. The article discusses in detail the oil and gas source characteristics of the Middle Permian and Lower-Middle Jurassic rocks, the molecular composition of oils and bitumoids from the OGSRs, and also interprets the characteristics of the biomarkers in them from the standpoint of the sedimentary-migration theory of oil generation. An attempt is made to explain the reasons for the difference in the properties and composition of oils from different OGCs. It is shown that the composition of hydrocarbon fluids of deposits is determined not only by the geological and geochemical conditions of sedimentation of oil and gas source deposits, but also associated with migration processes and subsequent secondary changes in the accumulation. In terms of composition, three groups of oils were identified: Permian and Jurassic heavy oils with a light carbon isotopic composition and the presence of β-carotene and gammacerane, they underwent different degrees of biodegradation, which depended on the geological conditions of the deposits; Permian medium oils in density (0.84 and 0.87 g/cm3), the composition of biomarkers of which is very close to that of the first group, and Jurassic light oils with a high content of solid paraffins and a heavier carbon isotopic composition, almost do not contain β-carotene and gammacerane concentrations are low.

THE EAST COAST BASIN OF NEW ZEALAND, AN EMERGING PETROLEUM PROVINCE

2005 ◽  
Vol 45 (1) ◽  
pp. 563 ◽  
Author(s):  
C.I. Uruski ◽  
B.D. Field ◽  
R. Funnell
Keyword(s):  
New Zealand ◽  
Seismic Data ◽  
Oil And Gas ◽  
East Coast ◽  
Data Set ◽  
Sequence Stratigraphic ◽  
Large Structures ◽  
Oil Generation ◽  
Wide Range ◽  
Reservoir Facies

More than 300 oil and gas seeps are known in the onshore East Coast Basin of North Island, New Zealand. Spectacular geological structures have been explored by more than 40 wells, only three of which have been offshore. Results are tantalising, with 70% of wells yielding oil or gas shows. Westech’s two gas discoveries onshore at Kauhauroa and Tuhara in northern Hawkes Bay remain un-developed at present.Strong gas shows were encountered in both open-file wells drilled offshore and elevated gas readings were recorded in the recent Tawatawa–1 well, but reservoir quality was poor.Nevertheless, good reservoir facies are abundant in the East Coast Basin. A wide range of Miocene and Pliocene sands and limestones, with porosities of 20% and above are known from outcrop and wells. But, modern, good quality seismic data are essential to allow sequence stratigraphic interpretation and a reasonable likelihood of predicting the distribution of reservoir facies. As part of its program to stimulate exploration in New Zealand, the NZ government is commissioning a new 4,000 km, highquality 2D seismic data set with the intention of making it freely available to interested exploration companies by mid-2005.The very thick sedimentary succession, the presence of direct hydrocarbon indicators on seismic data, the strong gas shows in wells drilled offshore and the reasonable expectation of oil generation and expulsion into numerous large structures with good reservoir facies combine to make the offshore East Coast Basin an attractive exploration venue.

New exploration opportunities in the offshore Houtman and Abrolhos sub-basins, northern Perth Basin, WA

2013 ◽  
Vol 53 (1) ◽  
pp. 97 ◽  
Author(s):  
Nadege Rollet ◽  
Chris Nicholson ◽  
Andrew Jones ◽  
Emmanuelle Grosjean ◽  
George Bernardel ◽  
...  
Keyword(s):  
Joint Venture ◽  
Oil And Gas ◽  
Strong Support ◽  
Lower Triassic ◽  
Source Rocks ◽  
Burial History ◽  
Sequence Stratigraphic ◽  
Petroleum Systems ◽  
Integrity Analysis ◽  
Geochemical Studies

The 2013 Acreage Release Areas W13-19 and W13-20 in the offshore northern Perth Basin, Western Australia, cover more than 19,000 km2 in parts of the Houtman, Abrolhos, Zeewyck and Gascoyne sub-basins. The Release Areas are located adjacent to WA-481-P, the only active offshore exploration permit in the Perth Basin, granted to joint venture partners Murphy Australia Oil Pty Ltd, Kufpec Australia Pty Ltd and Samsung Oil and Gas Australia Pty Ltd in August 2012. Geoscience Australia recently undertook a regional prospectivity study in the area as part of the Australian Government’s Offshore Energy Security Program, which provides fresh insights into basin evolution and hydrocarbon prospectivity. A sequence stratigraphic framework, based on new biostratigraphic sampling and interpretation, and an updated tectonostratigraphic model, using multiple 1D burial history models for Permian to Cenozoic sequences, have been developed. New geochemical studies of key offshore wells demonstrate that the oil-prone source interval of the Lopingian–Lower Triassic Hovea Member extends regionally offshore into the Abrolhos Sub-basin and potentially as far as the Houtman Sub-basin. This is supported by fluid inclusion data that provide evidence for palaeo-oil columns within Permian reservoirs in wells from the Abrolhos Sub-basin. Oil trapped in fluid inclusions in Houtman-1 can be linked to Jurassic source rocks, suggesting that multiple petroleum systems are effective in the Release Areas. The presence of active petroleum systems is also supported by the results of a recent marine survey. Potential seepage sites on the seafloor over reactivated faults correlate with hydroacoustic flares, pockmarks and dark colored viscous fluids that were observed over the areas. This may indicate an active modern-day petroleum system in the Houtman Sub-basin. Finally, a trap integrity analysis was undertaken to mitigate exploration risks associated with trap failure during Early Cretaceous breakup and provides a predictive approach to prospect assessment. These results provide strong support for the presence of active petroleum systems in the offshore northern Perth Basin and upgrade the prospectivity of the Release Areas.

Upper Miocene depositional environments of the Kikinda-Mokrin High (Serbia)

2018 ◽  
Vol 6 (1) ◽  
pp. SB65-SB76 ◽  
Author(s):  
Ivanišević Saša ◽  
Radivojević Dejan
Keyword(s):  
Sequence Stratigraphy ◽  
Oil And Gas ◽  
Pannonian Basin ◽  
Depositional Environments ◽  
Production Performance ◽  
Source Rocks ◽  
Shelf Edge ◽  
Lake Pannon ◽  
Upper Miocene ◽  
Temporal And Spatial

Exploration for oil and gas in mature areas, such as the Pannonian Basin, can benefit from reexamination of old data using more advanced modern workflows that focus on the temporal and spatial aspects of sediment deposition. Specifically, we apply a new environment of deposition model that interprets the Upper Miocene-Pliocene sediments as being deposited in a rapidly filling basin characterized by quick shelf edge progradation from the northwest toward the southeast. Reconstruction of this shelf edge trajectory reveals the absence of a Lake Pannon level drop during this time; rather, deposition was done during a highstand systems tract. We divided the Serbian postrift sediments into the Hetin, Majdan, Mokrin, Kikinda, and Paludina Formations used by geoscientists in Hungary and Slovakia. Hemipelagic marls of the Hetin Formation serve as the source rocks for the Majdan Formation basin-center turbidite reservoirs. These turbidite reservoirs are in turn sealed by clays and marls of the Mokrin slope formation. In contrast to previous interpretations of this part of the basin, our new sequence stratigraphy interpretation of the depositional environment interpretation significantly reduces the miscorrelation of the target sandstone reservoirs. Application of this sequence stratigraphy model also promises a better understanding of the other elements of the hydrocarbon system, which should lead to better production performance and reservoir management.

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