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.

THE OFFSHORE CARPENTARIA BASIN-GULF OF CARPENTARIA, NORTH QUEENSLAND

1994 ◽  
Vol 34 (1) ◽  
pp. 614
Author(s):  
B.A. McConachie ◽  
P.W. Stainton ◽  
M.G. Barlow ◽  
J.N. Dunster
Keyword(s):  
Early Cretaceous ◽  
Seismic Data ◽  
Late Jurassic ◽  
Source Rocks ◽  
Low Velocity ◽  
Reservoir Rocks ◽  
Half Graben ◽  
Reservoir Sandstones ◽  
Cape York ◽  
Velocity Channel

The Carpentaria Basin is late Jurassic to early Cretaceous in age and underlies most of the Gulf of Carpentaria and surrounding onshore areas. The Carpentaria Basin is stratigraphically equivalent to the Eromanga and Papuan Basins where similar reservoir rocks produce large volumes of hydrocarbons.Drillholes Duyken–1, Jackie Ck–1 and 307RD12 provide regional lithostratigraphic and tectonic control for the Q22P permit in the offshore Carpentaria Basin. Duyken–1 penetrated the upper seal section in the Carpentaria Basin and a full sequence through the overlying Karumba Basin. Jackin Ck–1 intersected the lower reservoir units and a condensed upper seal section of the Carpentaria Basin. Coal drillhole 307RD12 tested the late Jurassic to early Cretaceous reservoir section in the Carpentaria Basin and also intersected an underlying Permian infrabasin sequence.Little is known of the pre Jurassic sedimentary section below the offshore Carpentaria Basin but at least two different rock packages appear to be present. The most encouraging are relatively small, layered, low velocity, channel and half-graben fill, possibly related to Permian or Permo-Triassic sedimentary rocks to the east in the Olive River area. The other packages consist of poorly defined, discontinuous, high velocity rocks believed to be related to those of the Bamaga Basin which have been mapped further north.During the period 1990-1993 Comalco Aluminium Limited reprocessed 2188 km of existing seismic data and acquired 2657 km of new seismic data over the offshore Carpentaria Basin. When combined with onshore seismic and the results of drilling previously undertaken by Comalco near Weipa on northwestern Cape York Peninsula, it was possible to define a significant and untested play in the Carpentaria Depression, the deepest part of the offshore Carpentaria Basin.The main play in the basin is the late Jurassic to early Cretaceous reservoir sandstones and source rocks, sealed by thick early Cretaceous mudstones. Possible pre-Jurassic source rocks are also present in discontinuous fault controlled half-grabens underlying the Carpentaria Basin. New detailed basin modelling suggests both the lower part of the Carpentaria Basin and any pre Jurassic section are mature within the depression and any source rocks present should have expelled oil.

Northern Houtman Sub-basin prospectivity—preliminary results

2016 ◽  
Vol 56 (2) ◽  
pp. 577
Author(s):  
Irina Borissova ◽  
Chris Southby ◽  
George Bernardel ◽  
Jennifer Totterdell ◽  
Robbie Morris ◽  
...  
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Large Igneous Province ◽  
The North ◽  
Structural Style ◽  
Igneous Province ◽  
Line Spacing ◽  
History Of

In 2014–15 Geoscience Australia acquired 3,300 km of deep 2D seismic data over the northern part of the Houtman Sub-basin (Perth Basin). Prior to this survey, this area had a very sparse coverage of 2D seismic data with 50–70 km line spacing in the north and an industry grid with 20 km line spacing in the south. Initial interpretation of the available data has shown that the structural style, major sequences, and potential source rocks in this area are similar to those in the southern Houtman and Abrolhos sub-basins. The major difference between these depocentres, however, is in the volume and distribution of volcanic and intrusive igneous rocks. The northern part of the Houtman Sub-basin is adjacent to the Wallaby Plateau Large Igneous Province (LIP). The Wallaby Plateau and the Wallaby Saddle, which borders the western flank of the Houtman Sub-basin, had active volcanism from the Valanginian to at least the end of the Barremian. Volcanic successions significantly reduce the quality of seismic imaging at depth, making it difficult to ascertain the underlying thickness, geometry and structure of the sedimentary basin. The new 2D seismic dataset across the northern Houtman Sub-basin provides an opportunity for improved mapping of the structure and stratigraphy of the pre-breakup succession, assessment of petroleum prospectivity, and examination of the role of volcanism in the thermal history of this frontier basin.

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

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 A New Age Interpretation For The Meluhu Formation In Toronipa Peninsula, The Southeast Arm Of Sulawesi, Indonesia

2020 ◽  
Vol 70 (1) ◽  
pp. 103-118
Author(s):  
Achmad Fahruddin ◽  
◽  
Rakhmat Fakhruddin ◽  
Muhammad Firdaus ◽  
Hanif Mersil Saleh ◽  
...  
Keyword(s):  
Late Miocene ◽  
Oil And Gas ◽  
Sedimentary Facies ◽  
Source Rocks ◽  
Offshore Area ◽  
Facies Associations ◽  
Potential Reservoir ◽  
Pollen And Spores ◽  
Reservoir Potential ◽  
Exploration Well

The offshore area in the northeast of Kendari city, the southeast arm of Sulawesi, is an area with favourable hydrocarbon prospectivity shown by numerous oil and gas seeps in the surrounding coastal area. It is a frontier basin in eastern Indonesia, known as the Manui Basin. An exploration well named Abuki-1 was drilled in 1990 suggested a Miocene transgressive sequence as a potential reservoir and source rock at this basin. However, this unit has no analogous exposure in the onshore area resulting in the lack of study and knowledge of this potential Miocene unit. Therefore, we revisit the sedimentary rocks exposure nearby Abuki-1 well in the Toronipa peninsula to study about its sedimentary facies and palynological contents. These outcrops by previous researchers were included in Toronipa Member of Meluhu Formation, and a Triassic age was suggested for this unit. By contrast, our result shows that these exposures are Middle to Late Miocene in age as indicated by the occurrence of the Florschuetzia group pollens (Florschuetzia trilobata, F. levipoli, and F. meridionalis). The absence of Plio-Pleistocene pollen and spores index fossils (Stenochlaena milnei group, Dacrycarpus imbricatus, and Phyllocladus) supports the Middle to Late Miocene age interpretation. A wave-dominated estuary depositional model is proposed based on the presence of river-dominated, mixed-energy, and wave-dominated facies associations. We suggest that the studied sediments are the outcrop analogues for the Middle to Late Miocene transgressive sequence found in Abuki-1 well. Furthermore, we recommend that these Miocene estuary-fill complexes should have excellent hydrocarbon potential. The reservoir potential is the sand deposits of the fluvial, tidal, washover, and shoreface facies with moderately to well-sorted characteristics. The source rocks candidate is the mud of lagoon, tidal flat, floodplain, and marine offshore facies. Moreover, the Manui Basin, with its Miocene estuarine deposits, requires further study to reveal its hydrocarbon accumulation potential.

PETROLEUM POTENTIAL OF THE GREAT SOUTH BASIN, NEW ZEALAND—NEW SEISMIC DATA IMPROVES IMAGING

2007 ◽  
Vol 47 (1) ◽  
pp. 145 ◽  
Author(s):  
C. Uruski ◽  
C. Kennedy ◽  
T. Harrison ◽  
G. Maslen ◽  
R.A. Cook ◽  
...  
Keyword(s):  
New Zealand ◽  
Seismic Data ◽  
Oil And Gas ◽  
Petroleum Industry ◽  
Source Rocks ◽  
Seismic Survey ◽  
Recording Time ◽  
Petroleum Potential ◽  
South Basin ◽  
Time Migration

Much of the Great South Basin is covered by a 30,000 km grid of old seismic data, dating from the 1970s. This early exploration activity resulted in drilling eight wells, one of which, Kawau–1a, was a 461 Bcf gas-condensate discovery. Three other wells had significant oil and gas shows; in particular, Toroa–1 had extensive gas shows and 300 m oil shows. Cuttings are described in the geological logs as dripping with oil. The well was never tested due to engineering difficulties, meaning that much of the bore was accidentally filled with cement while setting casing.In early 2006, Crown Minerals, New Zealand’s petroleum industry regulating body, conducted a new 2D seismic survey in a previously lightly surveyed region across the northern part of the Great South Basin. While previous surveys were generally recorded for five seconds, sometimes six, with up to a 2,500-metre-long cable, the new survey, acquired by CGG Multiwave’s Pacific Titan, employed a 6,000-metre-long streamer and recorded for eight seconds.The dataset was processed to pre-stack time migration (PreSTM) by the GNS Science group using its access to the New Zealand Supercomputer. Increasing the recording time yielded dividends by more fully imaging, for the first time, the nature of rift faulting in the basin. Previous data showed only the tops of many fault blocks. The new data show a system of listric extensional faults, presumably soling out onto a mid-crust detachment. Sedimentary reflectors are observed to seven seconds, implying a thickness of up to 6,000 m of section, probably containing source rock units. The rotated fault blocks provide focal points for large compaction structures. The new data show amplitude anomalies and other features possibly indicating hydrocarbons associated with many of these structures. The region around the Toroa–1 well was typified by anomalously low velocities, which created a vertical zone of heavily attenuated reflections, particularly on intermediate processing products. The new data also show an amplitude anomaly at the well’s total depth (TD) which gives rise to a velocity push-down.Santonian age coaly source rocks are widespread and several reservoir units are recognised. The reservoir at Kawau–1a is the extensive Kawau Sandstone, an Early Maastrichtian transgressive unit sealed by a thick carbonate-cemented mudstone. In addition to the transgressive sandstone target, the basin also contains sandy Eocene facies, and Paleogene turbidite targets may also be attractive. Closed structures are numerous and many are very large with potential to contain billion barrel oil fields or multi-Tcf gas fields.

THE SOUTHERN BONAPARTE GULF BASIN - NEW PLAYS

1990 ◽  
Vol 30 (1) ◽  
pp. 52
Author(s):  
J.M. Durrant ◽  
R.E. France
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Well Control ◽  
Lost Circulation ◽  
Marine Source ◽  
Porosity And Permeability ◽  
Basin Floor ◽  
Relationship Of ◽  
New Phase ◽  
Live Oil

Integration of regional exploration data with a new basin model involving progressive basinward salt withdrawal has generated new exploration plays in WA-128-P and WA-211-P, which forms part of the offshore Southern Bonaparte Gulf. This area provides a hydrocarbon habitat that is unique to this part of the Bonaparte Gulf Basin.Three major Palaeozoic megasequences, MS-I, MS-II (A & B) and MS-III, are identified on seismic data and correspond to major stages in the structural and depositional development of the basin, from Silurian through to Triassic times.Early exploration, targeted on structural highs, encountered numerous hydrocarbon shows. Of most recent significance are the Turtle-1 and Turtle-2 wells. Turtle-1 (1984) targeted a midbasin, MS-I high and recovered oil in MS-III. Turtle-2 (1989) tested an additional 510 m-thick, MSII onlap sequence and encountered, within fractured intervals, significant oil and gas influx accompanied by massive lost circulation. Significant live oil was produced on test despite huge damage inflicted to the fracture porosity and permeability during the fourteen-day well control period.Recent geochemical work indicates that the oils recovered from MS-II and MS-III have a common marine source. Oils from MS-III are associated with incompetent seals and meteoric waters and are variably degraded and exhibit low GOR. In contrast, oils of MS-II, associated with competent seals, exhibit high GOR. In consequence, a diversity of new exploratory plays are indicated:Fractured reservoirs in MS-II, stratigraphic onlaps flanking MS-I structures.Stacked turbidites and basin floor fans deposited in the MS-II salt-withdrawal sub-basins.Carbonate banks within the MS-II sub-basin's marginal carbonate complexes.MS-I carbonate structures localised over early salt structures and onlapped by MS-II sediments.Structural and stratigraphic traps of MS-II and III associated with diapiric salt.By virtue of the stratigraphic and structural relationship of MS-II sediments which onlap the flanks of structural highs, these plays have not been previously drilled in optimal locations. Consequently, a new phase of exploration specifically targeted at these plays is now planned to proceed in parallel with exploration of MS-III targets in structural traps. The application of the basin model concepts to these MS-III plays has revealed subtle crestal faulting associated with structural highs. The structural and stratigraphic implications of these observations indicate new plays on the flanks of previously drilled structures.

Hudson Strait Platform and Basins Tectono-Sedimentary Element, Northeast Canada

2021 ◽  
pp. M57-2016-28
Author(s):  
Nicolas Pinet ◽  
Denis Lavoie ◽  
Shunxin Zhang
Keyword(s):  
Source Rocks ◽  
Hudson Bay ◽  
Upper Ordovician ◽  
Reservoir Rocks ◽  
Potential Reservoir ◽  
Half Graben ◽  
Topographical Feature ◽  
Sedimentary Succession ◽  
Marine Seismic ◽  
The One

AbstractThe Hudson Strait Platform and basins Tectono-Sedimentary Element (HSPB TSE) is part of a major topographical feature that connects Hudson Bay and Foxe Basin with the Labrador Sea in the Canadian Arctic. The Paleozoic succession (Ordovician–Silurian) unconformably overlies the Precambrian basement and reaches a maximum preserved thickness of less than 600 m on the islands. High-resolution marine seismic data indicate that the offshore part of the Hudson Strait is underlain by several fault-controlled sub-basins with a half-graben geometry. The sedimentary succession in the sub-basins is thicker than the one preserved in nearby islands, and includes an upper sedimentary package for which the nature and age remain poorly constrained. Upper Ordovician source rocks have been mapped onshore. Known potential reservoir rocks consist of Ordovician clastics and Ordovician–Silurian reefs and dolostones.

Stratigraphy and structure of the Drake Point Anticline, Sabine Peninsula, Canadian Arctic Islands

2016 ◽  
Vol 53 (12) ◽  
pp. 1484-1500 ◽  
Author(s):  
Keith Dewing ◽  
Virginia Brake ◽  
Mathieu J. Duchesne ◽  
Thomas A. Brent ◽  
Nancy Joyce
Keyword(s):  
Early Cretaceous ◽  
Canadian Arctic ◽  
Source Rocks ◽  
Lower Permian ◽  
Hydrocarbon Generation ◽  
Lower Paleozoic ◽  
Upper Paleozoic ◽  
Differential Movement ◽  
Half Graben ◽  
Structural Relief

Modern processing methods were applied to 3400 line-kilometres of legacy seismic data from Sabine Peninsula of Melville Island in the Canadian Arctic Islands. Post-stack reprocessing improved the imaging, allowing new insight into the following issues: the northern extent of lower Paleozoic source rocks, extensional structures and rock types in the upper Paleozoic succession, the timing of the gentle Drake Point Anticline; and the age and extent of igneous sills. The central part of Sabine Peninsula is underlain by a half-graben containing upper Paleozoic strata. The half-graben fill is intersected by just one well, but it likely contains Upper Carboniferous to Lower Permian strata. The two largest conventional gas fields in Canada (Drake Point and Hecla) are hosted in Mesozoic strata within a gentle anticline that partially overlies the half-graben. Previously, the Drake Point Anticline was interpreted to have been formed during Eocene time. We propose that 280 m of the 430 m of structural relief on the Drake Anticline formed in response to uplift at the axis of the anticline in the Early Cretaceous, as shown by thinning of the Lower Cretaceous Christopher Formation over the Drake Anticline. The remaining 150 m of structural relief formed by differential movement between the Marryatt Point Syncline and Drake Point Anticline after the Early Cretaceous. Early Cretaceous relief on the Drake Point Anticline means it was at least partially present at the time of maximum hydrocarbon generation in the Late Cretaceous.

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