Porosity trends and reservoir quality in the Bass Basin

2008 ◽  
Vol 48 (1) ◽  
pp. 227
Author(s):  
Natt Arian ◽  
Peter Tingate ◽  
Richard Hillis
Keyword(s):  
Source Rocks ◽  
Reservoir Quality ◽  
Hydrocarbon Generation ◽  
Relative Lack ◽  
Sonic Log ◽  
Exploration Risk ◽  
Hydrocarbon Charge ◽  
Gippsland Basin ◽  
Sand Bodies

A study of porosity trends and reservoir quality of the Eastern View Group (EVG) of the Bass Basin has been undertaken. Previous exploration in the Bass Basin targeted the Upper EVG due to its stratigraphic equivalence to the hydrocarbon-rich Upper Latrobe Group in the Gippsland Basin. Although this exploration has proved that mature source rocks in the basin have generated and expelled hydrocarbons, the relative lack of hydrocarbon charge into the Upper EVG has previously been identified as a major exploration risk. If hydrocarbon generation is adequate, the lack of Upper EVG accumulations is probably related to limited vertical migration. Thus the reservoir quality of the most relatively charged Middle and Lower EVG is important in determining the basins’ prospectivity. Sonic log data were deemed to be the most appropriate to determine porosity for this study. Wyllie, Clemenceau, Hunt-Raymer and modified Hunt-Raymer equations were used to calculate porosity. The results from each method were compared with available core plug data and the best method (modified Hunt-Raymer) selected. The modified Hunt-Raymer derived porosity trends were examined both vertically and laterally in the basin. In some sandstone intervals an increase in porosity with depth was observed. Thicker sand bodies can exhibit average calculated porosity of approximately 20% even at depths greater than 3,000 m. Several sands in the Middle EVG show a localised increase in porosity with depth, which is attributed to the fining upwards (coarsening downwards) of fluvial channels. The presence of good reservoir sands in the Middle and Lower EVG closer to mature source rocks in the basin is very encouraging as it makes deeper exploration in the Bass Basin more attractive.

scholarly journals Oil generation from coal source rocks: the influence of depositional conditions and stratigraphic age

2005 ◽  
Vol 7 ◽  
pp. 9-12 ◽  
Author(s):  
Henrik I. Petersen
Keyword(s):  
North Sea ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Oil Generation ◽  
Generation Capacity ◽  
The Subject ◽  
Coal Composition ◽  
Gippsland Basin ◽  
Australasian Region

Although it was for many years believed that coals could not act as source rocks for commercial oil accumulations, it is today generally accepted that coals can indeed generate and expel commercial quantities of oil. While hydrocarbon generation from coals is less well understood than for marine and lacustrine source rocks, liquid hydrocarbon generation from coals and coaly source rocks is now known from many parts of the world, especially in the Australasian region (MacGregor 1994; Todd et al. 1997). Most of the known large oil accumulations derived from coaly source rocks have been generated from Cenozoic coals, such as in the Gippsland Basin (Australia), the Taranaki Basin (New Zealand), and the Kutei Basin (Indonesia). Permian and Jurassic coal-sourced oils are known from, respectively, the Cooper Basin (Australia) and the Danish North Sea, but in general only minor quantities of oil appear to be related to coals of Permian and Jurassic age. In contrast, Carboniferous coals are only associated with gas, as demonstrated for example by the large gas deposits in the southern North Sea and The Netherlands. Overall, the oil generation capacity of coals seems to increase from the Carboniferous to the Cenozoic. This suggests a relationship to the evolution of more complex higher land plants through time, such that the highly diversified Cenozoic plant communities in particular have the potential to produce oil-prone coals. In addition to this overall vegetational factor, the depositional conditions of the precursor mires influenced the generation potential. The various aspects of oil generation from coals have been the focus of research at the Geological Survey of Denmark and Greenland (GEUS) for several years, and recently a worldwide database consisting of more than 500 coals has been the subject of a detailed study that aims to describe the oil window and the generation potential of coals as a function of coal composition and age.

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.

AN INTEGRATED GEOLOGICAL AND GEOPHYSICAL INTERPRETATION OF A PORTION OF THE OFFSHORE SYDNEY BASIN, NEW SOUTH WALES

2003 ◽  
Vol 43 (1) ◽  
pp. 495 ◽  
Author(s):  
P.A. Arditto
Keyword(s):  
New South ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Hydrocarbon Generation ◽  
Late Permian ◽  
Early Permian ◽  
South Wales ◽  
Permian Coal ◽  
Coal Measures ◽  
Reservoir Facies

The study area is within PEP 11, which is more than 200 km in length, covers an area over 8,200 km2 and lies immediately offshore of Sydney, Australia’s largest gas and petroleum market on the east coast of New South Wales. Permit water depths range from 40 m to 200 m. While the onshore Sydney Basin has received episodic interest in petroleum exploration drilling, no deep exploration wells have been drilled offshore.A reappraisal of available data indicates the presence of suitable oil- and wet gas-prone source rocks of the Late Permian coal measure succession and gas-prone source rocks of the middle to early Permian marine outer shelf mudstone successions within PEP 11. Reservoir quality is an issue within the onshore Permian succession and, while adequate reservoir quality exists in the lower Triassic succession, this interval is inferred to be absent over much of PEP 11. Quartz-rich arenites of the Late Permian basal Sydney Subgroup are inferred to be present in the western part of PEP 11 and these may form suitable reservoirs. Seismic mapping indicates the presence of suitable structures for hydrocarbon accumulation within the Permian succession of PEP 11, but evidence points to significant structuring post-dating peak hydrocarbon generation. Uplift and erosion of the order of 4 km (based on onshore vitrinite reflectance studies and offshore seismic truncation geometries) is inferred to have taken place over the NE portion of the study area within PEP 11. Published burial history modelling indicates hydrocarbon generation from the Late Permian coal measures commenced by or before the mid-Triassic and terminated during a mid-Cretaceous compressional uplift prior to the opening of the Tasman Sea.Structural plays identified in the western and southwestern portion of PEP 11 are well positioned to contain Late Permian clean, quartz-rich, fluvial to nearshore marine reservoir facies of the coal measures. These were sourced from the western Tasman Fold Belt. The reservoir facies are also well positioned to receive hydrocarbons expelled from adjacent coal and carbonaceous mudstone source rock facies, but must rely on early trap integrity or re-migrated hydrocarbons and, being relatively shallow, have a risk of biodegradation. Structural closures along the main offshore uplift appear to have been stripped of the Late Permian coal measure succession and must rely on mid-Permian to Early Permian petroleum systems for hydrocarbon generation and accumulation.

HYDROCARBON HABITAT OF THE COOPER/EROMANGA BASIN, AUSTRALIA

1983 ◽  
Vol 23 (1) ◽  
pp. 75 ◽  
Author(s):  
A. J. Kantsler ◽  
T. J. C. Prudence ◽  
A. C. Cook ◽  
M. Zwigulis
Keyword(s):  
Geothermal Gradient ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Oil Generation ◽  
Late Tertiary ◽  
Modelling Studies ◽  
Permian Coal ◽  
Intracratonic Basin ◽  
Hydrocarbon Charge ◽  
Eromanga Basin

The Cooper Basin is a complex intracratonic basin containing a Permian-Triassic succession which is uncomformably overlain by Jurassic-Cretaceous sediments of the Eromanga Basin. Abundant inertinite-rich humic source rocks in the Permian coal measures sequence have sourced some 3TCF recoverable gas and 300 million barrels recoverable natural gas liquids and oil found to date in Permian sandstones. Locally developed vitrinitic and exinite-rich humic source rocks in the Jurassic to Lower Cretaceous section have, together with Permian source rocks, contributed to a further 60 million barrels of recoverable oil found in fluvial Jurassic-Cretaceous sandstones.Maturity trends vary across the basin in response to a complex thermal history, resulting in a present-day geothermal gradient which ranges from 3.0°C/100 m to 6.0°C/100 m. Permian source rocks are generally mature to postmature for oil generation, and oil/condensate-prone and dry gas-prone kitchens exist in separate depositional troughs. Jurassic source rocks generally range from immature to mature but are postmature in the central Nappamerri Trough. The Nappamerri Trough is considered to have been the most prolific Jurassic oil kitchen because of the mature character of the crudes found in Jurassic reservoirs around its flanks.Outside the central Nappamerri Trough, maturation modelling studies show that most hydrocarbon generation followed rapid subsidence during the Cenomanian. Most syndepositional Permian structures are favourably located in time and space to receive this hydrocarbon charge. Late formed structures (Mid-Late Tertiary) are less favourably situated and are rarely filled to spill point.The high CO2 contents of the Permian gas (up to 50 percent) may be related to maturation of the humic Permian source rocks and thermal degradation of Permian crudes. However, the high δ13C of the CO2 (av. −6.9 percent) suggests some mixing with CO2 derived from thermal breakdown of carbonates within both the prospective sequence and economic basement.

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.

HYDROCARBON PROSPECTIVITY OF THE TORQUAY SUB-BASIN, OFFSHORE VICTORIA

1994 ◽  
Vol 34 (1) ◽  
pp. 479 ◽  
Author(s):  
Mark A. Trupp ◽  
Keith W. Spence ◽  
Michael J. Gidding
Keyword(s):  
Lower Cretaceous ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Structural Deformation ◽  
Hydrocarbon Generation ◽  
Fault Block ◽  
Complex Fault ◽  
Wild Dog ◽  
Reservoir Potential ◽  
Gippsland Basin

The Torquay Sub-basin lies to the south of Port Phillip Bay in Victoria. It has two main tectonic elements; a Basin Deep area which is flanked to the southeast by the shallower Snail Terrace. It is bounded by the Otway Ranges to the northwest and shallow basement elsewhere. The stratigraphy of the area reflects the influence of two overlapping basins. The Lower Cretaceous section is equivalent to the Otway Group of the Otway Basin, whilst the Upper Cretaceous and Tertiary section is comparable with the Bass Basin stratigraphy.The Torquay Sub-basin apparently has all of the essential ingredients needed for successful hydrocarbon exploration. It has good reservoir-seal pairs, moderate structural deformation and probable source rocks in a deep kitchen. Four play types are recognised:Large Miocene age anticlines, similar to those in the Gippsland Basin, with an Eocene sandstone reservoir objective;The same reservoir in localised Oligocene anticlines associated with fault inversion;Possible Lower Cretaceous Eumeralla Formation sandstones in tilted fault blocks and faulted anticlines; andLower Cretaceous Crayfish Sub-group sandstones also in tilted fault block traps.Maturity modelling suggests that the Miocene anticlines post-date hydrocarbon generation. Poor reservoir potential and complex fault trap geometries downgrade the two Lower Cretaceous plays.The Oligocene play was tested by Wild Dog-1 which penetrated excellent Eocene age reservoir sands beneath a plastic shale seal, however, the well failed to encounter any hydrocarbons. Post-mortem analysis indicates the well tested a valid trap. The failure of the well is attributed to a lack of charge. Remaining exploration potential is limited to the deeper plays which have much greater risks associated with each play element.

Impact of early hydrocarbon charge on the diagenetic history and reservoir quality of the Central Canyon sandstones in the Qiongdongnan Basin, South China Sea

2019 ◽  
Vol 185 ◽  
pp. 104022
Author(s):  
Guangxu Bi ◽  
Chengfu Lyu ◽  
Chao Li ◽  
Guojun Chen ◽  
Gongcheng Zhang ◽  
...  
Keyword(s):  
South China Sea ◽  
South China ◽  
Qiongdongnan Basin ◽  
Reservoir Quality ◽  
China Sea ◽  
Hydrocarbon Charge ◽  
Diagenetic History

scholarly journals Pre-Tertiary Basement Subcrops Beneath The Malay And Penyu Basins, Offshore Peninsular Malaysia: Their Recognition And Hydrocarbon Potential

2020 ◽  
Vol 70 (1) ◽  
pp. 163-193
Author(s):  
Mazlan Madon ◽  
◽  
John Jong ◽  
Franz L. Kessler ◽  
M. Hafiz Damanhuri ◽  
...  
Keyword(s):  
Fractured Reservoirs ◽  
Peninsular Malaysia ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Fractured Reservoir ◽  
Rock Types ◽  
Half Graben ◽  
Major Strike ◽  
Hydrocarbon Charge

Following the successful production from fractured basement in similar Tertiary basins, the basement play was pursued in the Malay Basin, particularly during the 2000-2010 period but, unfortunately, that effort fell short of expectations. The only oil discovery in fractured basement reservoir was Anding in the southwestern part of the basin. Despite its development being delayed due to economic reasons, the Anding discovery had been the basis for the basement play concept: namely, a fractured reservoir formed of pre-Tertiary metamorphic rock, charged from overlying Tertiary lacustrine source rocks in an adjacent half-graben and sealed by a transgressive shale unit. This paper examines seismic, gravity and well evidences on the pre-Tertiary basement geology, with the aim of assessing further the hydrocarbon potential of pre-Tertiary basement. The pre-Tertiary basement subcrops beneath the Malay and Penyu basins represent a continuation of the onshore geology of Sundaland Mesozoic terrane. Wells that penetrate the Base-Tertiary Unconformity (BTU) indicate a variety of rock types including igneous, metamorphic and sedimentary. Seismic data show the widespread presence of layered rocks beneath the BTU which could include potential new plays. Gravity modelling was carried out to help distinguish between pre-Tertiary layered rocks and Tertiary synrift sediments. Fractured reservoirs, like those discovered at Anding, seem to be associated with major strike-slip fault zones which are identifiable on high-quality seismic. Carbonate structures such as paleokarsts and buried hills are also recognisable and could potentially be mapped with seismic. These pre-Tertiary plays also rely on hydrocarbon charge mainly from the overlying Tertiary source rocks. Although Palaeozoic-Mesozoic source rocks may have passed their hydrocarbon generation stage, their gas potential cannot be ruled out.

MIGRATION, LEAKAGE AND SEEPAGE CHARACTERISTICS OF THE OFFSHORE CANNING BASIN AND NORTHERN CARNARVON BASIN: IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY

2003 ◽  
Vol 43 (2) ◽  
pp. 149 ◽  
Author(s):  
G.W. O’Brien ◽  
R. Cowley ◽  
G. Lawrence ◽  
A.K. Williams ◽  
M. Webster ◽  
...  
Keyword(s):  
Source Rocks ◽  
Large Area ◽  
Potential Field Data ◽  
Canning Basin ◽  
Basin Modelling ◽  
Exploration Risk ◽  
Northern Carnarvon Basin ◽  
Gas Chimneys ◽  
Hydrocarbon Charge ◽  
Carnarvon Basin

RadarSat and ERS Synthetic Aperture Radar (SAR) satellite data have been used for oil slick mapping as part of a systematic interpretative study of the offshore Canning Basin, as well as part of the northern Carnarvon Basin, extending from the inner shelf to the abyssal plain. These seepage data have been integrated with regional geological data, more than 12,000 km of reprocessed Airborne Laser Fluorosensor (ALF) survey data, seismic DHI indicators, water column geochemical sniffer data, potential field data, earthquake data and 2D Petromod basin modelling, to provide new insights into the region’s petroleum prospectivity and key exploration risk factors.From a prospectivity viewpoint, this study has highlighted several areas and processes. Firstly, it is clear that overpressure in the region is principally controlled by the thickness of the Tertiary carbonate wedge and we predict that overpressure may be present in parts of the deeper water Canning Basin. Secondly, the offshore Canning Basin contains a relatively low density of SAR-mapped oil slicks, though this appears to be due to a combination of factors, namely a paucity of vertical conduits for leakage, a predominantly condensate-prone charge and a small slick size.Significantly, several as-yet untested areas emerge from our observations. In the offshore Canning Basin, a 'window' exists in about 1,500–2,500 m of water, where the Triassic source rocks are particularly well placed for liquids generation. Morever, a large area in a radius some 20–80 km outboard of the Bedout High, also appears to have significant untested liquids potential, with respect to sourcing from the Triassic. The shallow section through this region contains a vast area with abundant seismically mapped gas chimneys and other seepage indicators, supporting the conclusions from the remote sensing and basin modelling of significant hydrocarbon charge in this region. Finally, the study indicates that liquids have been generated within the Palaeozoic section of the Bedout Sub-basin.

GIFFSLAND HYDROCARBONS - A PERSPECTIVE FROM THE BASIN EDGE

1984 ◽  
Vol 24 (1) ◽  
pp. 91 ◽  
Author(s):  
J. G. Stainforth
Keyword(s):  
Heat Flow ◽  
Upper Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Lower Tertiary ◽  
Late Tertiary ◽  
Carbonaceous Shales ◽  
Basin Edge ◽  
Gippsland Basin

Permit VIC/P19 lies palaeogeographically seaward of the main producing part of the Gippsland Basin. Deposition of the Latrobe Group commenced with volcanics and continental 'rift-stage' sediments during the Late Cretaceous. This phase was succeeded first by paludal sedimentation in the failed rift during the Campanian and Maastrichtian, and then by cyclic paralic sedimentation during the Paleocene and Eocene.Analysis of the hydrocarbons recovered during recent exploration of permit VIC/P19 shows that they were sourced from moderately mature coals and carbonaceous shales in the Campanian/-Maastrichtian paludal sequence.A maturation model that assumes elevated but decreasing heat flow, related to sea-floor spreading, produces an excellent fit to the observed maturity data and predicts a long history of hydrocarbon generation during the Tertiary. The maturity of the Upper Cretaceous source sequence depends more on the thickness of the overlying Lower Tertiary clastic Latrobe sediments than on the thickness of the Upper Tertiary carbonate wedge. The Late Tertiary phase of burial had relatively little effect on maturation because of its rapidity and the lower heat flow and higher thermal conductivities of the deeper sequence at the time. Overpressures in mature Upper Cretaceous source rocks, resulting from hydrocarbon generation, have driven pore fluids, including hydrocarbons, laterally up-dip into normally pressured reservoirs.The main oil province of the Gippsland Basin has a greater thickness of Lower Tertiary than has VIC/P19. As a result, source rocks are more mature there, and became wholly so by the end of deposition of the Latrobe Group. This facilitated charge of traps at the top of the Latrobe Group, which contain most of the oil and gas discovered to date in the Basin.

Sign in / Sign up

Export Citation Format

Share Document