EXPLORATION POTENTIAL OF THE TIMOR GAP ZONE OF CO-OPERATION

1990 ◽  
Vol 30 (1) ◽  
pp. 68 ◽  
Author(s):  
Peter Botten ◽  
Keiran Wulff
Keyword(s):  
Continental Shelf ◽  
Upper Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Small Data ◽  
Insufficient Information ◽  
Large Area ◽  
Potential Source ◽  
Timor Sea ◽  
Evaluation Of Data

The area covered by the Zone of Co-operation (ZOC) in the eastern Timor Sea represents the last large area of sparsely explored continental shelf around Australia that has obvious potential for significant hydrocarbon accumulations.Extravagant claims about the assumed exploration potential of the area have been widely published in Australia and Indonesia. The low level of exploration within the Zone does not allow confident prediction of potential at this time. Only five wells and less than 20 000 km of seismic are present in the ZOC. A similar level of exploration had been reached in the Ashmore-Cartier area in the western Timor Sea by 1972. With such a small data base, extrapolation of conclusions drawn from exploration of adjacent areas is fundamental to the present evaluation.Many technical comparisons can be made between the ZOC and the heavily explored Ashmore-Cartier area. Evaluation of data within the ZOC and extrapolation of important information from other parts of the Timor Sea indicates that all the prerequisites for hydrocarbon accumulations exist within the area.Jurassic reservoirs sealed by the Cretaceous Bathurst Island Formation provide the primary reservoir objectives in all areas of the ZOC away from the Malita Graben. Oil recovered in wells situated on the Londonderry High has been correlated with mature source rocks of the Jurassic Plover Formation in the Sahul Syncline. This depocentre is concluded to have the capacity of generating both oil and gas for potential accumulations in the southern and western part of the ZOC. The capacity of the Malita Graben to source major volumes of hydrocarbons from potential source rocks of the Flamingo Group is still to be established. Insufficient information is available to reliably predict the distribution of oil and gas in the ZOC.Play types similar to those seen in the Ashmore-Cartier area are present in the ZOC. Fault-controlled horst plays, typified by the Jabiru Field, are prevalent on the Sahul Platform. Upper Cretaceous sandstone plays dominate the southern part of the ZOC where reservoir objectives in the Jurassic Plover Formation and Flamingo Group are considered to be too deep for economic exploration.Application of some of the exploration lessons learnt in the western Timor Sea is essential to future activities in the ZOC in order to minimise possible discovery costs.

Upper Cretaceous palaeoenvironments and benthonic foraminiferal assemblages of potential source rocks from the western African margin, Central Atlantic

1999 ◽  
Vol 153 (1) ◽  
pp. 195-222 ◽  
Author(s):  
Ann Holbourn ◽  
Wolfgang Kuhnt ◽  
Abderrazzak El Albani ◽  
Thomas Pletsch ◽  
Florian Luderer ◽  
...  
Keyword(s):  
Upper Cretaceous ◽  
Source Rocks ◽  
Potential Source ◽  
Central Atlantic

scholarly journals Study on the Upper Paleozoic Source Rocks in Southwestern Henan, China

2021 ◽  
Vol 257 ◽  
pp. 03010
Author(s):  
Fengyu Sun ◽  
Gaoshe Cao ◽  
Zhou Xing
Keyword(s):  
Carbonate Rock ◽  
Oil And Gas ◽  
Lower Layer ◽  
Sedimentary Environment ◽  
Source Rocks ◽  
Oil And Gas Exploration ◽  
Potential Source ◽  
Upper Paleozoic ◽  
Unconventional Oil And Gas ◽  
Coal Rock

The Upper Paleozoic strata in Southwestern Henan have good prospects for unconventional oil and gas exploration. This paper takes the Upper Paleozoic source rocks in the Yuzhou area and the Pingdingshan area in Southwestern Henan as the research object, and tests 107 samples from the Upper Paleozoic coal rock, mudstone and carbonate rock. Combined with the sedimentary environment background, the Upper Paleozoic source rocks in Southwestern Henan are comprehensively evaluated. The results show that the Upper Paleozoic source rocks in Southwestern Henan, including coal rocks, mudstone and carbonate rocks, can be used as potential source rocks. Vertically, the source rocks are continuously distributed in the lower layer below the sandstone of Shanxi Formation. The Dazhan sandstone is only locally developed; the distribution of Upper Paleozoic source rocks in Southwestern Henan is mainly related to the Late Paleozoic transgression.

CONTINENTAL SHELF BASINS ON THE WEST TASMANIA MARGIN

1992 ◽  
Vol 32 (1) ◽  
pp. 231 ◽  
Author(s):  
A.M.G. Moore ◽  
J.B. Willcox ◽  
N.F. Exon ◽  
G.W. O'Brien
Keyword(s):  
Continental Shelf ◽  
Continental Slope ◽  
Late Cretaceous ◽  
Lower Cretaceous ◽  
Upper Cretaceous ◽  
Strike Slip ◽  
Source Rocks ◽  
Fault System ◽  
The West ◽  
Shallow Marine

The continental margin of western Tasmania is underlain by the southern Otway Basin and the Sorell Basin. The latter lies mainly under the continental slope, but it includes four sub-basins (the King Island, Sandy Cape, Strahan and Port Davey sub-basins) underlying the continental shelf. In general, these depocentres are interpreted to have formed at the 'relieving bends' of a major left-lateral strike-slip fault system, associated with 'southern margin' extension and breakup (seafloor spreading). The sedimentary fill could have commenced in the Jurassic; however, the southernmost sub-basins (Strahan and Port Davey) may be Late Cretaceous and Paleocene, respectively.Maximum sediment thickness is about 4300 m in the southern Otway Basin, 3600 m in the King Island Sub-basin, 5100 m in the Sandy Cape Basin, 6500 m in the Strahan Sub-basin, and 3000 m in the Port Davey Sub-basin. Megasequences in the shelf basins are similar to those in the Otway Basin, and are generally separated by unconformities. There are Lower Cretaceous non-marine conglomerates, sandstones and mudstones, which probably include the undated red beds recovered in two wells, and Upper Cretaceous shallow marine to non-marine conglomerates, sandstones and mudstones. The Cainozoic sequence often commences with a basal conglomerate, and includes Paleocene to Lower Eocene shallow marine sandstones, mudstones and marl, Eocene shallow marine limestones, marls and sandstones, and Oligocene and younger shallow marine marls and limestones.The presence of active source rocks has been demonstrated by the occurrence of free oil near TD in the Cape Sorell-1 well (Strahan Sub-basin), and thermogenic gas from surficial sediments recovered from the upper continental slope and the Sandy Cape Sub-basin. Geohistory maturation modelling of wells and source rock 'kitchens' has shown that the best locations for liquid hydrocarbon entrapment in the southern Otway Basin are in structural positions marginward of the Prawn-1 well location. In such positions, basal Lower Cretaceous source rocks could charge overlying Pretty Hill Sandstone reservoirs. In the King Island Sub-Basin, the sediments encountered by the Clam-1 well are thermally immature, though hydrocarbons generated from within mature Lower Cretaceous rocks in adjacent depocentres could charge traps, providing that suitable migration pathways are present. Whilst no wells have been drilled in the Sandy Cape Sub-basin, basal Cretaceous potential source rocks are considered to have entered the oil window in the early Late Cretaceous, and are now capable of generating gas/condensate. Upper Cretaceous rocks appear to have entered the oil window in the Paleocene. In the Strahan Sub-Basin, mature Cretaceous sediments in the depocentres are available to traps, though considerable migration distances would be required.It is concluded that the west Tasmania margin, which has five strike-slip related depocentres and the potential to have generated and entrapped hydrocarbons, is worthy of further consideration by the exploration industry. The more prospective areas are the southern Otway Basin, and the Sandy Cape and Strahan sub-basins of the Sorell Basin.

Geology and prospectivity of the Capel and Faust basins in the deepwater Tasman Sea region

2011 ◽  
Vol 51 (2) ◽  
pp. 702
Author(s):  
Takehiko Hashimoto ◽  
Karen Higgins ◽  
Nadege Rollet ◽  
Vaughan Stagpoole ◽  
Peter Petkovic ◽  
...  
Keyword(s):  
Upper Cretaceous ◽  
Source Rocks ◽  
Gas Generation ◽  
Potential Source ◽  
Tasman Sea ◽  
Sample Data ◽  
Frontier Region ◽  
Reduce Risk ◽  
Sedimentary Succession ◽  
The Government

Geoscience Australia recently completed a petroleum prospectivity assessment of the Capel and Faust basins as part of the Australian government's energy security program. This pre-competitive study was carried out in collaboration with GNS Science and the government of New Caledonian, and was based on seismic, potential field, multibeam bathymetry and sample data acquired during marine surveys in 2006–7. The Capel and Faust basins are located in the Tasman Sea region, which contains a number of deepwater basins. There is little information about their geology. The Geoscience Australia study confirmed the existence of large compartmentalised depocentres containing sediments up to 6 km thick. The basins formed during two Cretaceous extensional episodes related to the final breakup of eastern Gondwana. Syn-rift deposition appears to have been initially dominated by volcanics and volcaniclastics, then dominated by non-marine to shallow marine clastics. The post-rift succession comprises upward-fining clastic to calcareous bathyal sediments. A pre-rift (?Mesozoic) sedimentary succession appears to underlie some depocentres. Mesozoic successions in nearby eastern Australian and New Zealand basins suggest that fluvio-deltaic potential source rocks (Triassic/Jurassic to Upper Cretaceous coals) may occur in the pre-rift and syn-rift successions of the Capel and Faust basins. Multi-1D basin modelling suggests that the deeper depocentres are presently within the oil or gas generation window and that expulsion occurred from the Early Cretaceous. Fluvio-deltaic, shoreline and turbiditic sandstones may provide potential reservoirs. Likely play types include large anticlines, fault blocks, unconformities, and stratigraphic pinchouts. The results will guide future exploration and reduce risk in this vast frontier region.

scholarly journals Characteristics and evaluation of the Upper Paleozoic source rocks in the Southern North China Basin

2021 ◽  
Vol 13 (1) ◽  
pp. 294-309
Author(s):  
Fengyu Sun ◽  
Gaoshe Cao ◽  
Zhou Xing ◽  
Shuangjie Yu ◽  
Bangbang Fang
Keyword(s):  
Source Rock ◽  
North China ◽  
Oil And Gas ◽  
Source Rocks ◽  
Oil And Gas Exploration ◽  
Potential Source ◽  
Unconventional Oil ◽  
Upper Paleozoic ◽  
Unconventional Oil And Gas ◽  
North China Basin

Abstract The Upper Paleozoic coal measure strata in the Southern North China Basin have good potential for unconventional oil and gas exploration. However, there has been no systematic evaluation of potential source rock in this area; this affects the estimation of potential resources and the choice of exploratory target layers. In this study, full core holes ZK0901 and ZK0401, which perfectly reveal Upper Paleozoic strata in the study area, systematically collected and analyzed the samples for total organic carbon, rock pyrolysis, chloroform bitumen “A,” organic maceral, vitrinite reflectance, and kerogen carbon isotopes. The results showed that in addition to coal rocks, mudstones and carbonate rocks are also potential source rocks in the Upper Paleozoic strata. Vertically, the source rocks are continuous in Taiyuan Formation, the lower part of Shanxi Formation, and Lower Shihezi Formation. The organic matter type in the Upper Paleozoic coal rocks and mudstone source rock belong to type III or II. This phenomenon is mainly attributed to the special transgressive–regressive sedimentary environment of the carbonate rocks. The higher degree of thermal evolution in the Upper Paleozoic source rocks may be related to the structure or a higher paleogeothermal gradient in this area. The coal layer and its upper and lower mudstone of the Shanxi Formation and Lower Shihezi Formation are the main target layers of unconventional oil and gas exploration. The results from this study can be used as a reference for the study on potential source rock for unconventional oil and gas exploration in the Southern North China Basin.

scholarly journals Petroleum Geology and Geochemistry of Oils and Possible Source Rocks of the Southern East Coast Basin, New Zealand

2021 ◽  
Author(s):  
◽  
Nils Erik Elgar
Keyword(s):  
Source Rock ◽  
Black Shale ◽  
Oil And Gas ◽  
East Coast ◽  
Source Rocks ◽  
Higher Plant ◽  
Marine Organic Matter ◽  
Potential Source ◽  
Good Potential ◽  
Oil Source

<p>The East Coast Basin of New Zealand contains up to 10,000 m of predominantly fine-grained marine sediments of Early Cretaceous to Pleistocene age, and widespread oil and gas seepages testify to its status as a petroleum province. A suite of oils and possible source rocks from the southern East Coast Basin have been analysed by a variety of geochemical techniques to determine the hydrocarbon potential and establish oil-oil and oil-source rock correlations. Results of TOC and Rock-Eval pyrolysis indicate that the latest Cretaceous Whangai Formation and Paleocene Waipawa Black Shale represent the only good potential source rock sequences within the basin. The middle to Late Cretaceous Glenburn and Te Mai formations, previously considered good potential source rocks, are organic-rich (TOC contents up to 1.30% and 1.52% respectively), but comprise predominantly Types III and IV (structured terrestrial and semi-opaque) kerogen and, therefore, have little hydrocarbon generative potential (HI values < 50). Early Cretaceous and Neogene formations are shown to have low TOC contents and have little source rock potential. The Waipawa Black Shale is a widespread, thin (< 50 m), dark brown, non-calcareous siltstone. It contains up to 1.9% sulphur and elevated quantities of trace metals. Although immature to marginally mature for hydrocarbon generation in outcrop, it is organic-rich (TOC content up to 5.69%) and contains oil and gas-prone Types II and III kerogen. The extracted bitumen comprises predominantly marine algal and terrestrial higher plant material and indicates that deposition occurred under conditions of reduced oxygen with significant anoxic episodes. The Whangai Formation is a thick (300-500 m), non-calcareous to calcareous siliceous mudstone. Although immature to marginally mature in outcrop, the Upper Calcareous and Rakauroa members have a TOC content up to 1.37% and comprise oil and gas-prone Types II and III (structured aqueous and structured terrestrial) kerogen. Bitumen extracts comprise predominantly marine organic matter with a moderate terrestrial higher plant component and indicate that deposition occurred under mildly reducing conditions, with periodic anoxic episodes indicated for the Upper Calcareous Member. Two families of oils are recognised in the southern East Coast Basin. The Kerosene Rock, Westcott, Tiraumea and Okau Stream oils comprise both algal marine and terrestrial higher plant material and were deposited under periodically anoxic conditions. They are characterised by high relative abundances of unusual C30 steranes (C30 indices of 0.24-0.40) and 28,30-bisnorhopane, low proportions of C28 steranes and isotopically heavy [delta] 13C values (-20.9 to -23.0 [per mil]). The Waipatiki and Tunakore oils from southern Hawke's Bay and the Kora-1 oil from the northern Taranaki Basin have similar geochemical characteristics and are also included in this family of oils. These same characteristics are also diagnostic of the Waipawa Black Shale and an oil-source rock correlation is made on this basis. The Knights Stream and Isolation Creek oils are derived from predominantly marine organic matter with a moderate terrestrial angiosperm contribution, and characterised by low relative abundances of C30 steranes (C30 indices of 0.06-0.12) and 28,30-bisnorhopane, high proportions of C28 steranes and isotopically light [delta] 13C values (-26.8 to -28.9 [per mil]). Also included in this family of oils, with a slightly greater marine influence, are the major seep oils of the northern East Coast Basin (Waitangi, Totangi and Rotokautuku). A tentative oil-source rock correlation with the Upper Calcareous and Rakauroa members of the Whangai Formation is based on their similar geochemical characteristics.</p>

scholarly journals Evaluation of the quality, thermal maturity and distribution of potential source rocks in the Danish part of the Norwegian–Danish Basin

2008 ◽  
Vol 16 ◽  
pp. 1-66 ◽  
Author(s):  
Henrik I. Petersen ◽  
Lars H. Nielsen ◽  
Jørgen A. Bojesen-Koefoed ◽  
Anders Mathiesen ◽  
Lars Kristensen ◽  
...  
Keyword(s):  
Source Rock ◽  
Early Cretaceous ◽  
Middle Jurassic ◽  
Upper Cretaceous ◽  
Vitrinite Reflectance ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Thermal Maturity ◽  
Potential Source ◽  
Petroleum Generation

The quality, thermal maturity and distribution of potential source rocks within the Palaeozoic–Mesozoic succession of the Danish part of the Norwegian-Danish Basin have been evaluated on the basis of screening data from over 4000 samples from the pre-Upper Cretaceous succession in 33 wells. The Lower Palaeozoic in the basin is overmature and the Upper Cretaceous – Cenozoic strata have no petroleum generation potential, but the Toarcian marine shales of the Lower Jurassic Fjerritslev Formation (F-III, F-IV members) and the uppermost Jurassic – lowermost Cretaceous shales of the Frederikshavn Formation may qualify as potential source rocks in parts of the basin. Neither of these potential source rocks has a basinwide distribution; the present occurrence of the Lower Jurassic shales was primarily determined by regional early Middle Jurassic uplift and erosion. The generation potential of these source rocks is highly variable. The F-III and F-IV members show significant lateral changes in generation capacity, the best-developed source rocks occurring in the basin centre. The combined F-III and F-IV members in the Haldager-1, Kvols-1 and Rønde-1 wells contain 'net source-rock' thicknesses (cumulative thickness of intervals with Hydrogen Index (HI)> 200 mg HC/g TOC) of 40 m, 83 m, and 92 m, respectively, displaying average HI values of 294, 369 and 404 mg HC/g TOC. The Mors-1 well contains 123 m of 'net source rock' with an average HI of 221 mg HC/g TOC. Parts of the Frederikshavn Formation possess a petroleum generation potential in the Hyllebjerg-1, Skagen-2, Voldum-1 and Terne-1 wells, the latter well containing a c. 160 m thick highly oil-prone interval with an average HI of 478 mg HC/g TOC and maximum HI values> 500 mg HC/g TOC.The source-rock evaluation suggests that a Mesozoic petroleum system is the most likely in the study area. Two primary plays are possible: (1) the Upper Triassic – lowermost Jurassic Gassum play, and (2) the Middle Jurassic Haldager Sand play. Potential trap structures are widely distributed in the basin, most commonly associated with the flanks of salt diapirs. The plays rely on charge from the Lower Jurassic (Toarcian) or uppermost Jurassic – lowermost Cretaceous shales. Both plays have been tested with negative results, however, and failure is typically attributed to insufficient maturation (burial depth) of the source rocks. This maturation question has been investigated by analysis of vitrinite reflectance data from the study area, corrected for post-Early Cretaceous uplift. A likely depth to the top of the oil window (vitrinite reflectance = 0.6%Ro) is c. 3050–3100 m based on regional coalification curves. The Frederikshavn Formation had not been buried to this depth prior to post-Early Cretaceous exhumation, and the potential source rocks of the formation are thermally immature in terms of hydrocarbon generation. The potential source rocks of the Fjerritslev Formation are generally immature to very early mature. Mature source rocks in the Danish part of the Norwegian–Danish Basin are thus dependent on local, deeper burial to reach the required thermal maturity for oil generation. Such potential kitchen areas with mature Fjerritslev Formation source rocks may occur in the central part of the study area (central–northern Jylland), and a few places offshore. These inferred petroleum kitchens are areally restricted, mainly associated with salt structures and local grabens (such as the Fjerritslev Trough and the Himmerland Graben).

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.

Capel and Faust basins—integrated geoscientific assessment of Australia's remote offshore eastern frontier

2009 ◽  
Vol 49 (2) ◽  
pp. 586
Author(s):  
Takehiko Hashimoto ◽  
Karen Higgins ◽  
Ron Hackney ◽  
Vaughan Stagpoole ◽  
Chris Uruski ◽  
...  
Keyword(s):  
Upper Cretaceous ◽  
Oil And Gas ◽  
Early Stage ◽  
Gravity Data ◽  
Iterative Refinement ◽  
Source Rocks ◽  
Seismic Facies ◽  
Seismic Survey ◽  
Data Sets ◽  
Satellite Gravity

The paper discusses the results from the GA–302 2D seismic survey and GA–2436 (RV Tangaroa) marine reconnaissance survey over the Capel and Faust basins in the northern Tasman Sea. The integration of seismic, potential field and bathymetric data sets in 3D space at an early stage in the project workflow has assisted in the visualisation of the basin architecture, the interpolation of data between the seismic lines and the iterative refinement of interpretations. The data sets confirm the presence of multiple depocentres previously interpreted from satellite gravity data with a maximum sediment thickness of 5–7 km. Preliminary interpretation of the seismic data has identified two predominantly Cretaceous syn-rift and two Upper Cretaceous to Neogene sag megasequences overlying a heterogeneous pre-rift basement. The comparison of seismic facies and tectonostratigraphic history with offshore New Zealand and eastern Australian basins suggests the presence of possible Jurassic to Upper Cretaceous coaly and lacustrine source rocks in the pre-rift and syn-rift, and fluvio-deltaic to shallow marine reservoir rocks in the syn-rift to early post-rift successions. Preliminary 1D basin modelling suggests that the deeper depocentres of the Capel and Faust basins are within the oil and gas windows. Large potential stratigraphic and structural traps are also present.

scholarly journals Petroleum Geology and Geochemistry of Oils and Possible Source Rocks of the Southern East Coast Basin, New Zealand

2021 ◽  
Author(s):  
◽  
Nils Erik Elgar
Keyword(s):  
Source Rock ◽  
Black Shale ◽  
Oil And Gas ◽  
East Coast ◽  
Source Rocks ◽  
Higher Plant ◽  
Marine Organic Matter ◽  
Potential Source ◽  
Good Potential ◽  
Oil Source

<p>The East Coast Basin of New Zealand contains up to 10,000 m of predominantly fine-grained marine sediments of Early Cretaceous to Pleistocene age, and widespread oil and gas seepages testify to its status as a petroleum province. A suite of oils and possible source rocks from the southern East Coast Basin have been analysed by a variety of geochemical techniques to determine the hydrocarbon potential and establish oil-oil and oil-source rock correlations. Results of TOC and Rock-Eval pyrolysis indicate that the latest Cretaceous Whangai Formation and Paleocene Waipawa Black Shale represent the only good potential source rock sequences within the basin. The middle to Late Cretaceous Glenburn and Te Mai formations, previously considered good potential source rocks, are organic-rich (TOC contents up to 1.30% and 1.52% respectively), but comprise predominantly Types III and IV (structured terrestrial and semi-opaque) kerogen and, therefore, have little hydrocarbon generative potential (HI values < 50). Early Cretaceous and Neogene formations are shown to have low TOC contents and have little source rock potential. The Waipawa Black Shale is a widespread, thin (< 50 m), dark brown, non-calcareous siltstone. It contains up to 1.9% sulphur and elevated quantities of trace metals. Although immature to marginally mature for hydrocarbon generation in outcrop, it is organic-rich (TOC content up to 5.69%) and contains oil and gas-prone Types II and III kerogen. The extracted bitumen comprises predominantly marine algal and terrestrial higher plant material and indicates that deposition occurred under conditions of reduced oxygen with significant anoxic episodes. The Whangai Formation is a thick (300-500 m), non-calcareous to calcareous siliceous mudstone. Although immature to marginally mature in outcrop, the Upper Calcareous and Rakauroa members have a TOC content up to 1.37% and comprise oil and gas-prone Types II and III (structured aqueous and structured terrestrial) kerogen. Bitumen extracts comprise predominantly marine organic matter with a moderate terrestrial higher plant component and indicate that deposition occurred under mildly reducing conditions, with periodic anoxic episodes indicated for the Upper Calcareous Member. Two families of oils are recognised in the southern East Coast Basin. The Kerosene Rock, Westcott, Tiraumea and Okau Stream oils comprise both algal marine and terrestrial higher plant material and were deposited under periodically anoxic conditions. They are characterised by high relative abundances of unusual C30 steranes (C30 indices of 0.24-0.40) and 28,30-bisnorhopane, low proportions of C28 steranes and isotopically heavy [delta] 13C values (-20.9 to -23.0 [per mil]). The Waipatiki and Tunakore oils from southern Hawke's Bay and the Kora-1 oil from the northern Taranaki Basin have similar geochemical characteristics and are also included in this family of oils. These same characteristics are also diagnostic of the Waipawa Black Shale and an oil-source rock correlation is made on this basis. The Knights Stream and Isolation Creek oils are derived from predominantly marine organic matter with a moderate terrestrial angiosperm contribution, and characterised by low relative abundances of C30 steranes (C30 indices of 0.06-0.12) and 28,30-bisnorhopane, high proportions of C28 steranes and isotopically light [delta] 13C values (-26.8 to -28.9 [per mil]). Also included in this family of oils, with a slightly greater marine influence, are the major seep oils of the northern East Coast Basin (Waitangi, Totangi and Rotokautuku). A tentative oil-source rock correlation with the Upper Calcareous and Rakauroa members of the Whangai Formation is based on their similar geochemical characteristics.</p>

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