PETROLEUM POTENTIAL OF RAGAY GULF, SOUTHEAST LUZON, PHILIPPINES

1994 ◽  
Vol 34 (1) ◽  
pp. 707
Author(s):  
C.S. Lee ◽  
M.C. Galloway ◽  
J.B. Willcox ◽  
A.M.G. Moore ◽  
A.R. Fraser ◽  
...  
Keyword(s):  
International Development ◽  
Late Miocene ◽  
Seismic Data ◽  
Department Of Energy ◽  
Source Rocks ◽  
Geochemical Data ◽  
Petroleum Potential ◽  
Separate Source ◽  
Recent Sediments ◽  
Marine Seismic

During March-May 1992, the Australian Geological Survey Organisation and the Philippine Department of Energy conducted a cooperative marine seismic and underway geochemical survey in four offshore Philippine basins which included Ragay Gulf. The project was funded and supported by the Australian International Development Assistance Bureau.The newly acquired and reprocessed seismic data from Ragay Gulf show a significant improvement in penetration and stratigraphic resolution. Seismic interpretation has revealed the existence of five sedimentary sub-basins with 2.5 – 6 seconds of Eocene to Recent sediments. Several potential traps have been evaluated for hydrocarbon reserves and new prospects are identified.No well has been drilled offshore in the Ragay Gulf. Onshore well log information and stratigraphy have assisted in the correlation and interpretation of offshore seismic data and allowed potential reservoirs to be recognised. The primary reservoir targets are the carbonate sequences of both Early and Late Miocene age. The widespread volcanoclastic sand may be an important secondary target, especially for gas reservoirs.Onshore and offshore geochemical data have confirmed the presence of mature source rocks from which generated hydrocarbons are currently migrating to the surface and, by inference, to reservoirs.A wide diversity of play types is recognised which could have been sourced from three separate source kitchens in the Bondoc, Ragay and Burlas Sub-basins. Specific entrapment possibilities are:Compressional fault-dependent traps (e.g. Anima Sola).Compressional anticlinal fault independent traps (e.g. Alibijaban and Palad).Late Miocene carbonate reefal buildups (e.g. Apud and Gorda).Early Miocene carbonate reservoirs in drape over highs (e.g. San Narciso and Bagulaya).

THE GEOLOGY AND EVOLUTION OF THE SCOTT PLATEAU

1978 ◽  
Vol 18 (1) ◽  
pp. 34 ◽  
Author(s):  
H. M. J. Stagg
Keyword(s):  
Seismic Data ◽  
Seismic Reflection ◽  
Structural Evolution ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Reservoir Rocks ◽  
Carbonate Sedimentation ◽  
Sea Bed ◽  
Adjacent Part ◽  
Water Depths

The Scott Plateau and the adjacent Rowley Terrace cover about 130,000 km2 beyond Australia's Northwest Shelf in water depths ranging from 300 m to 3000 m. The regional geology and structural evolution of the area have been interpreted from about 13,000 km of seismic reflection profiles.The Scott Plateau forms a subsided oceanward margin to the Browse Basin. For much of the period from the Carboniferous to the Middle Jurassic, preceding the breakup which formed this part of the continental margin, the Scott Plateau was probably above sea level shedding sediment into the developing Browse Basin. After breakup in the Bathonian to Callovian, the plateau subsided, until by the Late Cretaceous open marine conditions were prevalent over most of the area, with the probable exception of some structurally high areas which may have remained emergent until early in the Tertiary. Carbonate sedimentation commenced in the Santonian and has continued to the present, with major hiatuses in the Paleocene and Oligocene. Analysis of magnetic and seismic data indicates that, over much of the plateau, economic basement of possible Kimberley Block equivalents is probably no more than 3 to 4 km below sea bed. To the south of the Scott Plateau, the Rowley Terrace is underlain by a wedge of at least 6 km of Mesozoic and Tertiary sediments of the northeast- trending Rowley Sub - basin. The Rowley Sub -basin connects with the Beagle Sub-basin to the southwest and probably connects with the Browse Basin to the northeast. It has been largely unaffected by episodes of faulting, except in the southwest where faulting and folding are pronounced. The petroleum potential of the Scott Plateau is not rated highly. The potential hydrocarbon-bearing sediments here are probably no younger than Palaeozoic. These are quite likely to be only 2 to 4 km thick, and any hydrocarbons generated within them would probably have been lost during the protracted period of emergence and erosion that preceded breakup. The hydrocarbon potential appears to be greater in the Rowley Sub-basin, where Triassic to Cretaceous shale and siltstone source rocks, and Triassic to Lower Cretaceous sandstone reservoir rocks are expected to be present. However, the potential of these sequences is downgraded because hydrocarbon shows in exploration wells on the adjacent part of the Northwest Shelf have been only minor, and by the apparent scarcity of suitable traps. Exploitation of any hydrocarbons would be costly owing to the great water depths.

Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data

2011 ◽  
Vol 51 (2) ◽  
pp. 746
Author(s):  
Irina Borissova ◽  
Gabriel Nelson
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Magnetic Data ◽  
Long Distance ◽  
Potential Field Data ◽  
Petroleum Potential ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data ◽  
Insight Into ◽  
Carnarvon Basin

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin. Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics. Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays. Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.

A geochemical investigation into the resource potential of the Lawn Hill Platform, northern Australia

2020 ◽  
Vol 60 (2) ◽  
pp. 722
Author(s):  
Amber J. M. Jarrett ◽  
Adam E. H. Bailey ◽  
Christopher J. Boreham ◽  
Tehani Palu ◽  
Lisa Hall ◽  
...  
Keyword(s):  
Organic Geochemistry ◽  
Source Rocks ◽  
Geochemical Data ◽  
Northern Australia ◽  
Hydraulic Stimulation ◽  
Petroleum Potential ◽  
North West ◽  
North Eastern ◽  
Resource Exploration ◽  
Geochemical Investigation

The Lawn Hill Platform (LHP) is a sedimentary province in north-eastern Northern Territory and north-western Queensland that hosts a significant Paleoproterozoic–Mesoproterozoic sequence, often referred to as 'the ‘Isa Superbasin’, and includes the overlying South Nicholson Group. Shale gas resources and base-metals mineralisation are known in north-west Queensland, but the larger basin is underexplored. The Australian Government’s Exploring for the Future (EFTF) 2016−2020 program aims to boost resource exploration in northern Australia. New precompetitive geochemical data obtained in this program includes source rock geochemistry, kerogen kinetics, bitumen reflectance, biomarker and δ13C n-alkanes for understanding the petroleum potential, organic geochemistry of source rocks and fluids, stratigraphic correlations and mineralogy to determine the brittleness of shales. All data and derived reports are accessible on the EFTF portal (www.eftf.ga.gov.au), providing a central location for informed decision making. The results in this study demonstrate fair to excellent source rocks in multiple supersequences that are brittle and favourable to hydraulic stimulation. A comparison to the greater McArthur Basin demonstrates, that although there are many similarities in bulk geochemistry, LHP mudstones are largely heterogeneous, reflecting local variations that may be inherited from variations in contributing biomass, microbial reworking, depositional environment, sediment input and paleoredox conditions.

AN ALTERNATIVE VIEW ON INDO-AUSTRALIAN COALS AS A SOURCE OF PETROLEUM

1994 ◽  
Vol 34 (1) ◽  
pp. 256 ◽  
Author(s):  
Barry Jay Katz
Keyword(s):  
Northern Hemisphere ◽  
Genetic Relationships ◽  
Primary Source ◽  
Source Rocks ◽  
Geochemical Data ◽  
Alternative View ◽  
Apparent Absence ◽  
Petroleum Potential ◽  
Marine Source ◽  
Oil Source

Numerous studies have argued that coals are the primary source for much of the petroleum in the Indo-Australian region. These studies have invoked this genetic relationship because of similarities in n-alkane distributions among coal extracts and oils and the apparent absence of conventional sources. Others have suggested that the ability of southern hemisphere coals to source oil is a result of differences in the nature of their precursors compared to their gas-prone northern hemisphere counterparts.Suggested genetic relationships are challenged through several independent approaches. Organic geochemical data reveal that these coals display characteristics similar to their northern hemisphere, gas-prone counterparts. They appear capable of generating large volumes of heavy hydrocarbons but are incapable of expelling them within the oil-window. Other data reveal that many of the region's proposed oil-source rock correlations are internally inconsistent. And finally, data are becoming available which indicate that conventional lacustrine or marginal marine source rocks are present.This alternative view of the petroleum potential of coals is significant in that it alters exploration concepts and mass-balance calculations of reserves.

Pre-Messinian Petroleum Systems and Trap Style in the Offshore Western of Nile Delta; An Integrated Geological and Geophysical Approach

2016 ◽  
Author(s):  
Mostafa Monir ◽  
Omar Shenkar
Keyword(s):  
Seismic Data ◽  
Nile Delta ◽  
Lower Pressure ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Geochemical Data ◽  
Peak Oil ◽  
West Nile ◽  
Petroleum Systems ◽  
Well Data

ABSTRACT Exploration in the offshore Nile Delta province has revealed several hydrocarbon plays. Deep marine Turbidites is considered one of the most important plays for hydrocarbon exploration in the Nile Delta. These turbidites vary from submarine turbidite channels to submarine basin floor fans. An integrated exploration approach was applied for a selected area within West Delta Deep Marine (WDDM) Concession offshore western Nile Delta using a variety of geophysical, geological and geochemical data to assess the prospectivity of the Pre-Messinian sequences. This paper relies on the integration of several seismic data sets for a new detailed interpretation and characterization of the sub-Messinian structure and stratigraphy based on regional correlation of seismic markers and honoured the well data. The interpretation focused mainly on the Oligocene and Miocene mega-sequences. The seismic expression of stratigraphic sequences shows a variety of turbidite channel/canyon systems having examples from West Nile delta basin discoveries and failures. The approach is seismically based focusing on seismic stratigraphic analysis, combination of structure and stratigraphic traps and channels interpretation. Linking the geological and geophysical data together enabled the generation of different sets of geological models to reflect the spatial distribution of the reservoir units. The variety of tectonic styles and depositional patterns in the West Nile delta provide favourable trapping conditions for hydrocarbon generations and accumulations. The shallow oil and gas discoveries in the Pliocene sands and the high-grade oils in the Oligo-Miocene and Mesozoic reservoirs indicate the presence of multiple source rocks and an appropriate conditions for hydrocarbon accumulations in both biogenic and thermogenic petroleum systems. The presence of multi-overpressurized intervals in the Pliocene and Oligo-Miocene Nile delta stratigraphic column increase the depth oil window and the peak oil generation due to decrease of the effective stress. Fluids have the tendency to migrate from high pressure zones toward a lower pressure zones, either laterally or vertically. Also, hydrocarbons might migrate downward if there is a lower pressure in the deeper layers. Well data and the available geochemical database have been integrated with the interpreted seismic data to identify potential areas of future prospectivity in the study area.

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 Lower Triassic Caley Member: depositional facies, reservoir quality and seismic expression

2018 ◽  
Vol 58 (2) ◽  
pp. 878 ◽  
Author(s):  
Jack Woodward ◽  
Jon Minken ◽  
Melissa Thompson ◽  
Margarita Kongawoin ◽  
Laurence Hansen ◽  
...  
Keyword(s):  
Seismic Data ◽  
Lower Triassic ◽  
Source Rocks ◽  
Geochemical Data ◽  
Reservoir Quality ◽  
Depositional Facies ◽  
Efficient System ◽  
Delta Plain ◽  
Porosity And Permeability ◽  
Thin Reservoir

Recent exploration success in the Lower Keraudren Formation of the Bedout sub-basin has resulted in the emergence of the Caley Member reservoirs (Thompson et al. 2018). The interplay of several unique characteristics at this stratigraphic level are favourable for the generation, trapping and deliverability of hydrocarbons. These unique characteristics include, the preservation of porosity and permeability at depths greater than 4000 m, an organic-rich delta-plain lagoon mudstone source rock interbedded with the reservoir and the presence of a thick hemi-pelagic shale. This proximity of the mature source rocks and reservoir quality units combined with a thick overlying shale has created a highly efficient system for trapping hydrocarbons. Seismic data is a key tool to help unlock this play. Seismic imaging of a relatively thin reservoir at a depth below 4000 m has proved challenging. Quadrant has undertaken several stages of reprocessing and conducted multiple seismic inversions to better image and predict the reservoir. Integration and interpretation of geophysical, geological and geochemical data of this recently discovered reservoir has increased Quadrant’s understanding of the potential of the under-explored Bedout sub-basin.

Assessing source rock distribution in Heather and Draupne Formations of the Norwegian North Sea: A workflow using organic geochemical, petrophysical, and seismic character

2015 ◽  
Vol 3 (3) ◽  
pp. SV45-SV68 ◽  
Author(s):  
Balazs Badics ◽  
Anthony Avu ◽  
Sean Mackie
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Seismic Data ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Geochemical Data ◽  
Seismic Attribute ◽  
Attribute Analysis ◽  
Seismic Characterization ◽  
Petrophysical Logs

The organic-rich upper Jurassic Draupne and Heather Formations are the main proven source rocks of the Norwegian North Sea. We have developed a workflow for the organic geochemical, petrophysical, and seismic characterization of the Draupne and Heather Formation source rocks in a [Formula: see text] study area in quadrant 25 in the Viking Graben in the Norwegian North Sea. We characterized the vertical and lateral organic richness variations using biostratigraphy, organic geochemical data, and petrophysical logs. The Draupne Formation is a rich (6.5 wt.% total organic carbon [TOC], 360 HI), oil-prone, immature to early oil mature source rock, representing a 25-m-thick condensed section, partly eroded over the Utsira high and thickening to 150–300 m toward the deep grabens. The underlying Heather Formation is also an oil-prone (4.4 wt.% TOC, 270 HI), 30- to 400-m-thick, more mature source rock. To map the TOC distribution using seismic, we performed detailed seismic interpretation and seismic attribute analysis following the petrophysical calibration of TOC with the [Formula: see text] ratio and P impedance on well data. Similar patterns of low-impedance high-TOC areas highlighted and mapped from the petrophysical studies at the Heather level were also observed on seismic relative acoustic impedance and amplitude maps over the study area. The poststack seismic data conditioning (structurally orientated noise reduction) improved the quality of the input megamerge seismic data and allowed the application of colored inversion, structural and fault imaging, as well as multiattribute combination and visualization techniques, which have been efficient in highlighting the distribution of high-TOC areas, structure and fault zones within the study area.

Formation geological depth image according to refraction and reflection marine seismic data

2017 ◽  
Vol 39 (6) ◽  
pp. 106-121
Author(s):  
A. O. Verpahovskaya ◽  
V. N. Pilipenko ◽  
Е. V. Pylypenko
Keyword(s):  
Seismic Data ◽  
Depth Image ◽  
Marine Seismic

A possible new hydrocarbon play, offshore central West Greenland

1998 ◽  
pp. 28-30
Author(s):  
Nina Skaarup ◽  
James A. Chalmers
Keyword(s):  
Seismic Data ◽  
Mineral Resources ◽  
Source Rocks ◽  
Bright Spot ◽  
Offshore Area ◽  
West Greenland ◽  
The Government ◽  
Structural Closure ◽  
Multichannel Seismic Data ◽  
Seismic Lines

NOTE: This article was published in a former series of GEUS Bulletin. Please use the original series name when citing this article, for example: Skaarup, N., & Chalmers, J. A. (1998). A possible new hydrocarbon play, offshore central West Greenland. Geology of Greenland Survey Bulletin, 180, 28-30. https://doi.org/10.34194/ggub.v180.5082 _______________ The discovery of extensive seeps of crude oil onshore central West Greenland (Christiansen et al. 1992, 1994, 1995, 1996, 1997, 1998, this volume; Christiansen 1993) means that the central West Greenland area is now prospective for hydrocarbons in its own right. Analysis of the oils (Bojesen-Koefoed et al. in press) shows that their source rocks are probably nearby and, because the oils are found within the Lower Tertiary basalts, the source rocks must be below the basalts. It is therefore possible that in the offshore area oil could have migrated through the basalts and be trapped in overlying sediments. In the offshore area to the west of Disko and Nuussuaq (Fig. 1), Whittaker (1995, 1996) interpreted a few multichannel seismic lines acquired in 1990, together with some seismic data acquired by industry in the 1970s. He described a number of large rotated fault-blocks containing structural closures at top basalt level that could indicate leads capable of trapping hydrocarbons. In order to investigate Whittaker’s (1995, 1996) interpretation, in 1995 the Geological Survey of Greenland acquired 1960 km new multichannel seismic data (Fig. 1) using funds provided by the Government of Greenland, Minerals Office (now Bureau of Minerals and Petroleum) and the Danish State through the Mineral Resources Administration for Greenland. The data were acquired using the Danish Naval vessel Thetis which had been adapted to accommodate seismic equipment. The data acquired in 1995 have been integrated with the older data and an interpretation has been carried out of the structure of the top basalt reflection. This work shows a fault pattern in general agreement with that of Whittaker (1995, 1996), although there are differences in detail. In particular the largest structural closure reported by Whittaker (1995) has not been confirmed. Furthermore, one of Whittaker’s (1995) smaller leads seems to be larger than he had interpreted and may be associated with a DHI (direct hydrocarbon indicator) in the form of a ‘bright spot’.

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