PROSPECTIVITY AND EXPLORATION HISTORY OF THE BARROW SUB-BASIN, WESTERN AUSTRALIA

1997 ◽  
Vol 37 (1) ◽  
pp. 117 ◽  
Author(s):  
P.W. Baillie ◽  
E.P. Jacobson
Keyword(s):  
Lower Cretaceous ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Liquid Hydrocarbons ◽  
Reservoir Rocks ◽  
Long Period ◽  
Porosity And Permeability ◽  
History Of ◽  
Hydrocarbon Reserves

The Carnarvon Basin is Australia's leading producer of both liquid hydrocarbons and gas. Most oil production to date has come from the Barrow Sub-basin. The success of the Sub-basin is due to a fortuitous combination of good Mesozoic source rocks which have been generating over a long period of time, Lower Cretaceous reservoir rocks with excellent porosity and permeability, and a thick and effective regional seal.A feature of Barrow Sub-basin fields is that they generally produce far more petroleum than is initially estimated and booked, a result of the excellent reservoir quality of the principal producing reservoirs.Structural traps immediately below the regional seal (the 'top Barrow play') have been the most successful play to date. Analysis of 'new' and 'old' play concepts show that the Sub-basin has potential for significant additional hydrocarbon reserves.

scholarly journals Impact of basin evolution, depositional environment, pore water evolution and diagenesis on reservoir-quality of Lower Paleozoic Haima Supergroup sandstones, Sultanate of Oman

GeoArabia ◽  
2004 ◽  
Vol 9 (4) ◽  
pp. 107-138
Author(s):  
Karl Ramseyer ◽  
Joachim E. Amthor ◽  
Christoph Spötl ◽  
Jos M.J. Terken ◽  
Albert Matter ◽  
...  
Keyword(s):  
Pore Water ◽  
Depositional Environment ◽  
Liquid Hydrocarbon ◽  
Gas Condensate ◽  
Reservoir Quality ◽  
Liquid Hydrocarbons ◽  
Eastern Flank ◽  
Oman Mountains ◽  
Hydrocarbon Charge

ABSTRACT Sandstones of the Early Paleozoic Miqrat Formation and Barik Sandstone Member (Haima Supergroup) are the most prolific gas/condensate containing units in the northern part of the Interior Oman Sedimentary Basin (IOSB). The reservoir-quality of these sandstones, buried to depths exceeding 5 km, is critically related to the depositional environment, burial-related diagenetic reactions, the timing of liquid hydrocarbon charge and the replacement of liquid hydrocarbon by gas/condensate. The depositional environment of the sandstones controls the net-sand distribution which results in poorer reservoir properties northwards parallel to the axis of the Ghaba Salt Basin. The sandy delta deposits of the Barik Sandstone Member have a complex diagenetic history, with early dolomite cementation, followed by compaction, chlorite formation, hydrocarbon charge, quartz and anhydrite precipitation and the formation of pore-filling and pore-lining bitumen. In the Miqrat Formation sandstone, which is comprised of inland sabkha deposits, similar authigenic minerals occur, but with higher abundances of dolomite and anhydrite, and less quartz cement. The deduced pore water evolution from deposition to recent, in both the Miqrat Formation and the Barik Sandstone Member, reflects an early addition of saline continental waters and hydrocarbon-burial related mineral reactions with the likely influx of lower-saline waters during the obduction of the Oman Mountains. Four structural provinces are recognized in the IOSB based on regional differences in the subsidence/uplift history: the Eastern Flank, the Ghaba and Fahud Salt Basins and the Mabrouk-Makarem High. In the Fahud Salt Basin, biodegradation of an early oil charge during Late Paleozoic uplift resulted in reservoir-quality degradation by bitumen clogging of the pore space. On the Eastern Flank and the Mabrouk-Makarem High, however, the early oil bypassed the area. In contrast, post-Carboniferous liquid hydrocarbons were trapped in the Mabrouk-Makarem High, whereas on the Eastern Flank surface water infiltration and loss of hydrocarbons or biodegradation to pore occluding bitumen occurred. In the Ghaba Salt Basin, post-Carboniferous hydrocarbon charge induced a redox reaction to form porosity/permeability preserving chlorite in the reservoirs. The liquid hydrocarbons were replaced since the obduction of the Oman Mountains by gas/condensate which prevented the deep parts (>5,000 m) of the Ghaba Salt Basin from pore occluding pyrobitumen and thus deterioration of the reservoir quality.

THE HYDROCARBON POTENTIAL OF THE PENOLA TROUGH, OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 358 ◽  
Author(s):  
R. Lovibond ◽  
R.J. Suttill ◽  
J.E. Skinner ◽  
A.N. Aburas
Keyword(s):  
Early Cretaceous ◽  
Seismic Data ◽  
Oil And Gas ◽  
Direct Detection ◽  
Source Rocks ◽  
Well Control ◽  
Potential Reservoir ◽  
Half Graben ◽  
History Of

The Penola Trough is an elongate, Late Jurassic to Early Cretaceous, NW-SE trending half graben filled mainly with synrift sediments of the Crayfish Group. Katnook-1 discovered gas in the basal Eumeralla Formation, but all commercial discoveries have been within the Crayfish Group, particularly the Pretty Hill Formation. Recent improvements in seismic data quality, in conjunction with additional well control, have greatly improved the understanding of the stratigraphy, structure and hydrocarbon prospectivity of the trough. Strati-graphic units within the Pretty Hill Formation are now mappable seismically. The maturity of potential source rocks within these deeper units has been modelled, and the distribution and quality of potential reservoir sands at several levels within the Crayfish Group have been studied using both well and seismic data. Evaluation of the structural history of the trough, the risk of a late carbon dioxide charge to traps, the direct detection of gas using seismic AVO analysis, and the petrophysical ambiguities recorded in wells has resulted in new insights. An important new play has been recognised on the northern flank of the Penola Trough: a gas and oil charge from mature source rocks directly overlying basement into a quartzose sand sequence referred to informally as the Sawpit Sandstone. This play was successfully tested in early 1994 by Wynn-1 which flowed both oil and gas during testing from the Sawpit Sandstone. In mid 1994, Haselgrove-1 discovered commercial quantities of gas in a tilted Pretty Hill Formation fault block adjacent to the Katnook Field. These recent discoveries enhance the prospectivity of the Penola Trough and of the Early Cretaceous sequence in the wider Otway Basin where these sediments are within reach of the drill.

PROVENANCE, DIAGENESIS AND RESERVOIR QUALITY OF THE LOWER CRETACEOUS SANDSTONE OF THE ORANGE BASIN, SOUTH AFRICA.

2011 ◽  
Vol 114 (3-4) ◽  
pp. 433-448 ◽  
Author(s):  
O. A. FADIPE ◽  
P. F. CAREY ◽  
A. AKINLUA ◽  
S. A. ADEKOLA
Keyword(s):  
South Africa ◽  
Lower Cretaceous ◽  
Reservoir Quality

scholarly journals Reservoir Quality of Upper Jurassic Corallian Sandstones, Weald Basin, UK

Geosciences ◽  
2021 ◽  
Vol 11 (11) ◽  
pp. 446
Author(s):  
Dinfa Vincent Barshep ◽  
Richard Henry Worden
Keyword(s):  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Upper Jurassic ◽  
Reservoir Quality ◽  
Main Process ◽  
Shallow Marine ◽  
Porosity And Permeability ◽  
Calcite Cement ◽  
Diagenetic Evolution

The Upper Jurassic, shallow marine Corallian sandstones of the Weald Basin, UK, are significant onshore reservoirs due to their future potential for carbon capture and storage (CCS) and hydrogen storage. These reservoir rocks, buried to no deeper than 1700 m before uplift to 850 to 900 m at the present time, also provide an opportunity to study the pivotal role of shallow marine sandstone eodiagenesis. With little evidence of compaction, these rocks show low to moderate porosity for their relatively shallow burial depths. Their porosity ranges from 0.8 to 30% with an average of 12.6% and permeability range from 0.01 to 887 mD with an average of 31 mD. The Corallian sandstones of the Weald Basin are relatively poorly studied; consequently, there is a paucity of data on their reservoir quality which limits any ability to predict porosity and permeability away from wells. This study presents a potential first in the examination of diagenetic controls of reservoir quality of the Corallian sandstones, of the Weald Basin’s Palmers Wood and Bletchingley oil fields, using a combination of core analysis, sedimentary core logs, petrography, wireline analysis, SEM-EDS analysis and geochemical analysis to understand the extent of diagenetic evolution of the sandstones and its effects on reservoir quality. The analyses show a dominant quartz arenite lithology with minor feldspars, bioclasts, Fe-ooids and extra-basinal lithic grains. We conclude that little compactional porosity-loss occurred with cementation being the main process that caused porosity-loss. Early calcite cement, from neomorphism of contemporaneously deposited bioclasts, represents the majority of the early cement, which subsequently prevented mechanical compaction. Calcite cement is also interpreted to have formed during burial from decarboxylation-derived CO2 during source rock maturation. Other cements include the Fe-clay berthierine, apatite, pyrite, dolomite, siderite, quartz, illite and kaolinite. Reservoir quality in the Corallian sandstones show no significant depositional textural controls; it was reduced by dominant calcite cementation, locally preserved by berthierine grain coats that inhibited quartz cement and enhanced by detrital grain dissolution as well as cement dissolution. Reservoir quality in the Corallian sandstones can therefore be predicted by considering abundance of calcite cement from bioclasts, organically derived CO2 and Fe-clay coats.

scholarly journals KLASIFIKASI PETROFISIKA TIPE BATUAN UNTUK MEMPREDIKSI KUALITAS RESERVOAR PASIR SERPIHAN PADA FORMASI TALANG AKAR, CEKUNGAN ONWJ

2020 ◽  
Vol 4 (3) ◽  
pp. 28-40
Author(s):  
Feni Priyanka ◽  
Ordas Dewanto ◽  
Bagus Sapto Mulyatno ◽  
Riezal Ariffiandhany
Keyword(s):  
Property Values ◽  
Type Method ◽  
Reservoir Rocks ◽  
Petrophysical Property ◽  
Flow Units ◽  
A Value ◽  
Geological Conditions ◽  
Porosity And Permeability ◽  
Hydraulic Flow Units

Hydrocarbons were accumulated in reservoir, the reservoir has a lot of types depending on the geological conditions and the constituent mineral. In ONWJ basins, sub-basins Arjuna, Talang Akar Formation is sand splintersreservoir type. The presence of clay in a reservoir will reduce the resistivity and increase thesaturation, so it takes a multimineral analysis and the reservoir qualityclassification. In this study, physical properties (porosity, permeability, Rw, and saturation) and the quality of the reservoir can be identified through petrophysical analysis by utilizing log data and core analysis, and the rocktypeprediction(using R35 Winland or HFU method). In this study 5 wells (IX-A1, IX-13, IX-4, IX-7 and IX-8)used and found eight hydrocarbon zones, 6 are validated by the DST (drill steam test)data, androck type method that suitable is the method of HFU (hydraulic flow units) due to the coefficient of correlation between porosity and permeability shows a value of 0.75, based on the calculations, the eight types of rock is conclude, where the dominance of the rock typeis the type 12 with a pore size between 5-10 microns, type reservoir rocks in this study belong to the lithofacies distributary channel and mouthbar sand. By knowing the petrophysical property values, it can determine reservoir productivity and determine the zone eligible to be produced or not, by using curve SMLP (Stratigraphic Modified Lorenz Plot).

Lower Cretaceous stratigraphic characteristics and tectonic control of the eastern depression, North Yellow Sea Basin, North China

2020 ◽  
Vol 57 (10) ◽  
pp. 1180-1192
Author(s):  
Zhen Zhang ◽  
Rihui Cheng ◽  
Yanjie Shen ◽  
Liaoliang Wang ◽  
Xiaoqiang Hu ◽  
...  
Keyword(s):  
Yellow Sea ◽  
Lower Cretaceous ◽  
North China ◽  
Strike Slip ◽  
Lateral Movement ◽  
Third Order ◽  
Reservoir Rocks ◽  
North Yellow Sea ◽  
The North

The Lower Cretaceous of the eastern depression in the North Yellow Sea Basin is a set of residual strata that can be divided into K1sq1 and K1sq2 sequences. There are four lithology–lithofacies architectures summarized in the third-order sequences of wells W5, W3, W1, W9, W16, W7, W8, and W10, and they are the coarse–fine–coarse, asymmetric coarse–fine, asymmetric fine–coarse, and interbedded coarse and fine. F1, F4, F6, and F7, which are strike-slip faults, were dominant during the Early Cretaceous, and controlled the eastern depression to undergo right-lateral movement from transtension to transpression. The tectonic movement controlled different stratigraphic structure in different areas, and the fan bodies deposited along the basin margin and progradated into the basin center. The sequence models under extensional and strike-slip setting were established respectively. The transtension–transpression movement controlled the development of the sandstones in the Lower Cretaceous and improved the quality of the reservoir rocks.

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