scholarly journals PROSPEK SUMBER DAYA ENERGI BERDASARKAN ANALISIS POLA ANOMALI GAYA BERAT DI DAERAH BIAK DAN SEKITARNYA, PAPUA

2016 ◽  
Vol 13 (2) ◽  
pp. 87 ◽  
Author(s):  
Saultan Panjaitan ◽  
Subagio Subagio
Keyword(s):  
Gravity Anomaly ◽  
Oil And Gas ◽  
East Coast ◽  
Gravity Anomalies ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Ultramafic Rocks ◽  
Reservoir Rocks ◽  
Northern City ◽  
Fluid Reservoir

Hasil penelitian gayaberat di Pulau Biak menghasilkan anomali gayaberat yang dikelompokkan kedalam 2 (dua) satuan yaitu anomali gayaberat 50 mGal hingga 120 mGal membentuk rendahan anomali mencerminkan cekungan. Kelompok anomali gayaberat 120 mGal hingga 220 mGal membentuk tinggian anomali. Pola tinggian anomali sisa 0 mGal hingga 2 mGal diduga sebagai perangkap struktur migas yang terdapat di daerah Kota Biak utara, Mandon dan lepas pantai timur P. Pai. Batuan bertahanan jenis rendah antara 0 - 16 Ohm-meter yang mengindikasikan batuan reservoir jenuh fluida terbentuk di kedalaman 2500 meter. Kedalaman batuan dasar terbentuk antara 7000-8500 meter, dengan rapat massa batuan 2.9 - 3.1 gr/cm3 bertahanan jenis tinggi 1000-8200 Ohm-meter diduga sebagai cerminan dari batuan ultramafik kerak samudera. Batuan yang menyusun di daerah penelitian terdiri atas lapisan batuan Tersier dengan rapat massa 2.45 gr/cm3, batuan Pra-Tersier dengan rapat massa 2.75 gr/cm3 dan batuan dasar dengan rapat massa 3.1 gr/cm3. Batuan sumber adalah serpih Formasi Makat berumur Miosen dengan rapat massa batuan 2.45 gr/cm3, sedangkan batuan reservoir terdiri dari batupasir Formasi Mamberamo. Kata kunci Gayaberat, cekungan, migas, anomali sisa, rapat massa, sesar, antiklin, batuan sumber, tahanan jenis. Gravity research on the island of Biak gravity anomalies are grouped into two (2) units is a gravity anomaly 50 mgal up to 120 mgal is basin reflecting. Gravity anomaly 120 mgal up to 220 mgal formed heights anaomaly. Altitude residual anomaly from 0 mGal to 2 mgal is oil and gas as trapping structures contained in the northern City of Biak, off the east coast Mandon and P. Pai. The rocks is of low resistivity between 0 -16 Ohm-meter that indicates the saturated fluid reservoir rocks are in the depths of 2500 meter. The depth of the bedrock formed between 7000-8500 meters, with density 2.9 - 3.1 gr / cm3 is heights resistivity types of 1000-8200 Ohm-meter interpreted as a reflection of ultramafic rocks oceanic crust. The rocks in the study area consists of Tertiary rocks layers with a density 2.45 gr / cm3, the Pre-Tertiary rocks with density 2.75 gr / cm3 and bedrock with density 3.1 gr / cm3. The source rocks is of shale from Makat Formation Miocene age with density 2.45 gr / cm3, and the reservoir rock consists of sandstone Mamberamo Formation. Keywords: Gravity, basin, oil and gas, recidual anomaly, density, fault, anticline, source rocks, resistivity.

scholarly journals Konfigurasi Cekungan Tomori Berdasarkan Data Gayaberat

2019 ◽  
Vol 20 (1) ◽  
pp. 27
Author(s):  
Tatang Padmawidjaja
Keyword(s):  
Gravity Anomaly ◽  
Oil And Gas ◽  
Sedimentary Rocks ◽  
Bouguer Anomaly ◽  
Reservoir Rock ◽  
Ultramafic Rocks ◽  
Geophysical Research ◽  
Rock Density ◽  
Basin Area ◽  
Subsurface Modeling

Geophysical research in Tomori Basin, Kolonodale Bay using the gravity method was carried out to identified anticline structural trap in associated with hydrocarbon prospect. The occurence of hydrocarbon seepage in some places, indicate that hydrocarbon have been formed although its distribution is not clearly known. The gravity Bouguer anomaly resulted two groups of rock units: the group of 40 mGal up to 120 mGal gravity anomaly represent ultramafic rocks, and group of 30 mGal up to -80 mGal gravity anomaly reflected a sedimentary rocks basin. The subsurface modeling of the rock density can be grouped into three layers: the Cenozoic (2.5-2.55 gr/cm³ density), the Mesozoic (2.6-2.7 gr/cm³ density), and the Basement ( 2.8-2.9 gr/cm³ density). Elongated and vertical closure are reflected by anomaly 0-2 mGal with density 2.5 gr/cm3 to 2:55 mGal which is supposed to be oil and gas structures. The Source rock is characterized by  0  to -10 mGal anomaly  interpreted as oil kitchen at sub-basin area. Location of the reservoir rock is assumed in the Cenozoic layer on Salodik Group with density of 2.5 gr/cm³. The Basement is estimated at depth of 3.5-4 km, derived from the Group of metamorphic and volcanic rocks.Keyword: Gravity, basin, residual anomaly, fault, anticline. DOI:10.33332/jgsm.2019.v20.1.27-36

scholarly journals Konfigurasi Cekungan Tomori Berdasarkan Data Gayaberat

2019 ◽  
Vol 20 (1) ◽  
pp. 27
Author(s):  
Tatang Padmawidjaja
Keyword(s):  
Gravity Anomaly ◽  
Oil And Gas ◽  
Sedimentary Rocks ◽  
Bouguer Anomaly ◽  
Reservoir Rock ◽  
Ultramafic Rocks ◽  
Geophysical Research ◽  
Rock Density ◽  
Basin Area ◽  
Subsurface Modeling

Geophysical research in Tomori Basin, Kolonodale Bay using the gravity method was carried out to identified anticline structural trap in associated with hydrocarbon prospect. The occurence of hydrocarbon seepage in some places, indicate that hydrocarbon have been formed although its distribution is not clearly known. The gravity Bouguer anomaly resulted two groups of rock units: the group of 40 mGal up to 120 mGal gravity anomaly represent ultramafic rocks, and group of 30 mGal up to -80 mGal gravity anomaly reflected a sedimentary rocks basin. The subsurface modeling of the rock density can be grouped into three layers: the Cenozoic (2.5-2.55 gr/cm³ density), the Mesozoic (2.6-2.7 gr/cm³ density), and the Basement ( 2.8-2.9 gr/cm³ density). Elongated and vertical closure are reflected by anomaly 0-2 mGal with density 2.5 gr/cm3 to 2:55 mGal which is supposed to be oil and gas structures. The Source rock is characterized by  0  to -10 mGal anomaly  interpreted as oil kitchen at sub-basin area. Location of the reservoir rock is assumed in the Cenozoic layer on Salodik Group with density of 2.5 gr/cm³. The Basement is estimated at depth of 3.5-4 km, derived from the Group of metamorphic and volcanic rocks.Keyword: Gravity, basin, residual anomaly, fault, anticline.

scholarly journals Konfigurasi Cekungan Tomori Berdasarkan Data Gayaberat

2019 ◽  
Vol 20 (1) ◽  
pp. 27
Author(s):  
Tatang Padmawidjaja
Keyword(s):  
Gravity Anomaly ◽  
Oil And Gas ◽  
Sedimentary Rocks ◽  
Bouguer Anomaly ◽  
Reservoir Rock ◽  
Ultramafic Rocks ◽  
Geophysical Research ◽  
Rock Density ◽  
Basin Area ◽  
Subsurface Modeling

Geophysical research in Tomori Basin, Kolonodale Bay using the gravity method was carried out to identified anticline structural trap in associated with hydrocarbon prospect. The occurence of hydrocarbon seepage in some places, indicate that hydrocarbon have been formed although its distribution is not clearly known. The gravity Bouguer anomaly resulted two groups of rock units: the group of 40 mGal up to 120 mGal gravity anomaly represent ultramafic rocks, and group of 30 mGal up to -80 mGal gravity anomaly reflected a sedimentary rocks basin. The subsurface modeling of the rock density can be grouped into three layers: the Cenozoic (2.5-2.55 gr/cm³ density), the Mesozoic (2.6-2.7 gr/cm³ density), and the Basement ( 2.8-2.9 gr/cm³ density). Elongated and vertical closure are reflected by anomaly 0-2 mGal with density 2.5 gr/cm3 to 2:55 mGal which is supposed to be oil and gas structures. The Source rock is characterized by  0  to -10 mGal anomaly  interpreted as oil kitchen at sub-basin area. Location of the reservoir rock is assumed in the Cenozoic layer on Salodik Group with density of 2.5 gr/cm³. The Basement is estimated at depth of 3.5-4 km, derived from the Group of metamorphic and volcanic rocks.Keyword: Gravity, basin, residual anomaly, fault, anticline.

scholarly journals Konfigurasi Cekungan Tomori Berdasarkan Data Gayaberat

2019 ◽  
Vol 20 (1) ◽  
pp. 27
Author(s):  
Tatang Padmawidjaja
Keyword(s):  
Gravity Anomaly ◽  
Oil And Gas ◽  
Sedimentary Rocks ◽  
Bouguer Anomaly ◽  
Reservoir Rock ◽  
Ultramafic Rocks ◽  
Geophysical Research ◽  
Rock Density ◽  
Basin Area ◽  
Subsurface Modeling

Geophysical research in Tomori Basin, Kolonodale Bay using the gravity method was carried out to identified anticline structural trap in associated with hydrocarbon prospect. The occurence of hydrocarbon seepage in some places, indicate that hydrocarbon have been formed although its distribution is not clearly known. The gravity Bouguer anomaly resulted two groups of rock units: the group of 40 mGal up to 120 mGal gravity anomaly represent ultramafic rocks, and group of 30 mGal up to -80 mGal gravity anomaly reflected a sedimentary rocks basin. The subsurface modeling of the rock density can be grouped into three layers: the Cenozoic (2.5-2.55 gr/cm³ density), the Mesozoic (2.6-2.7 gr/cm³ density), and the Basement ( 2.8-2.9 gr/cm³ density). Elongated and vertical closure are reflected by anomaly 0-2 mGal with density 2.5 gr/cm3 to 2:55 mGal which is supposed to be oil and gas structures. The Source rock is characterized by  0  to -10 mGal anomaly  interpreted as oil kitchen at sub-basin area. Location of the reservoir rock is assumed in the Cenozoic layer on Salodik Group with density of 2.5 gr/cm³. The Basement is estimated at depth of 3.5-4 km, derived from the Group of metamorphic and volcanic rocks.Keyword: Gravity, basin, residual anomaly, fault, anticline. DOI:10.33332/jgsm.2019.v20.1.27-36

The discovery of a new sedimentary basin: offshore Raukumara, East Coast, North Island, New Zealand

2008 ◽  
Vol 48 (1) ◽  
pp. 53 ◽  
Author(s):  
Chris Uruski ◽  
Callum Kennedy ◽  
Rupert Sutherland ◽  
Vaughan Stagpoole ◽  
Stuart Henrys
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
East Coast ◽  
Plate Boundary ◽  
Source Rocks ◽  
Fault System ◽  
Northern Coast ◽  
The South ◽  
Petroleum Potential ◽  
The North

The East Coast of North Island, New Zealand, is the site of subduction of the Pacific below the Australian plate, and, consequently, much of the basin is highly deformed. An exception is the Raukumara Sub-basin, which forms the northern end of the East Coast Basin and is relatively undeformed. It occupies a marine plain that extends to the north-northeast from the northern coast of the Raukumara Peninsula, reaching water depths of about 3,000 m, although much of the sub-basin lies within the 2,000 m isobath. The sub-basin is about 100 km across and has a roughly triangular plan, bounded by an east-west fault system in the south. It extends about 300 km to the northeast and is bounded to the east by the East Cape subduction ridge and to the west by the volcanic Kermadec Ridge. The northern seismic lines reveal a thickness of around 8 km increasing to 12–13 km in the south. Its stratigraphy consists of a fairly uniformly bedded basal section and an upper, more variable unit separated by a wedge of chaotically bedded material. In the absence of direct evidence from wells and samples, analogies are drawn with onshore geology, where older marine Cretaceous and Paleogene units are separated from a Neogene succession by an allochthonous series of thrust slices emplaced around the time of initiation of the modern plate boundary. The Raukumara Sub-basin is not easily classified. Its location is apparently that of a fore-arc basin along an ocean-to-ocean collision zone, although its sedimentary fill must have been derived chiefly from erosion of the New Zealand land mass. Its relative lack of deformation introduces questions about basin formation and petroleum potential. Although no commercial discoveries have been made in the East Coast Basin, known source rocks are of marine origin and are commonly oil prone, so there is good potential for oil as well as gas in the basin. New seismic data confirm the extent of the sub-basin and its considerable sedimentary thickness. The presence of potential trapping structures and direct hydrocarbon indicators suggest that the Raukumara Sub-basin may contain large volumes of oil and gas.

scholarly journals Analysis of the Petroleum System of Dima Oil Field by Using PetroMoD 1D

2021 ◽  
pp. 526-531
Author(s):  
Haider A. F. Al-Tarim
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Petroleum System ◽  
Oil Field ◽  
Reservoir Rock ◽  
Geological Time ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Geological Age ◽  
Stratigraphic Succession

The study of petroleum systems by using the PetroMoD 1D software is one of the most prominent ways to reduce risks in the exploration of oil and gas by ensuring the existence of hydrocarbons before drilling.      The petroleum system model was designed for Dima-1 well by inserting several parameters into the software, which included the stratigraphic succession of the formations penetrating the well, the depths of the upper parts of these formations, and the thickness of each formation. In addition, other related parameters were investigated, such as lithology, geological age, periods of sedimentation, periods of erosion or non-deposition, nature of units (source or reservoir rocks), total organic carbon (TOC), hydrogen index (HI) ratio of source rock units, temperature of both surface and formations as they are available, and well-bottom temperature.      Through analyzing the models by the evaluation of the source rock units, the petrophysical properties of reservoir rock units, and thermal gradation with the depth during the geological time, it became possible to clarify the elements and processes of the petroleum system of the field of Dima. It could be stated that Nahr Umr, Zubair, and Sulaiy formations represent the petroleum system elements of Dima-1 well.

scholarly journals POLA ANOMALI GAYABERAT DAERAH TALIABU-MANGOLE DAN LAUT SEKITARNYA TERKAIT DENGAN PROSPEK MINYAK BUMI DAN GAS

2016 ◽  
Vol 12 (2) ◽  
pp. 65
Author(s):  
Saultan Panjaitan ◽  
Subagio Subagio
Keyword(s):  
Gravity Anomaly ◽  
Late Cretaceous ◽  
Middle Jurassic ◽  
Late Jurassic ◽  
Oil And Gas ◽  
Research Area ◽  
Black Shales ◽  
Reservoir Rocks ◽  
Gas Seepage ◽  
Anomaly Pattern

Anomali gayaberat di daerah penelitian merupakan anomali tertinggi di Indonesia, secara umum dikelompokkan ke dalam 2 (dua) satuan, yaitu: kelompok anomali gayaberat 160 mGal hingga 260 mGal membentuk pola rendahan/cekungan anomali, dan kelompok anomali gayaberat 260 mGal hingga 620 mGal membentuk pola tinggian anomali. Anomali sisa 0 mGal hingga 5 mGal membentuk tinggian anomali, diduga merupakan gambaran antiklin dengan diameter 10 – 15 kilometer. Perangkap struktur migas di daerah Minaluli, Madafuhi dan Lekosula Pulau Mangole berdekatan dengan lokasi rembesan migas, sehingga diusulkan untuk dilakukan pemboran eksplorasi. Sedangkan di Pulau Taliabu, Tolong, Pena, Samuya dan Teluk Jiko masih perlu dilakukan penambahan data. Batuan reservoir terdiri dari batupasir dan batugamping Formasi Tanamu berumur Kapur Akhir, menempati daerah beranomali sisa 0 mGal hingga 5 mGal, dengan rapat massa batuan sekitar 2.65 gr/cm³. Batuan induk adalah Formasi Buya umur Jura Tengah - Jura Akhir dari serpih hitam dengan rapat massa 2.71 gr/cm³, dan dapur migas terbentuk di sekitar daerah beranomali sisa -4 mGal hingga -28 mGal yang membentuk sub-cekungan di utara lepas pantai Pulau Mangole. Kata kunci: gayaberat, dapur minyak, cekungan, migas, serpih hitam, anomali sisa, rapat massa, antiklin, batuan induk. The gravity anomaly of research area is the highest anomaly in Indonesia, generally it can be grouped into 2 (two) units, that are 160 mGal up to 260 mGal anomaly groups formed low anomaly pattern, and 260 mGal up to 620 mGal anomaly groups formed high anomaly pattern. 0 mGal to 5 mGal residual anomaly formed high anomaly pattern, it is interpreted as anticline with diameter are 10-15 kilometers. The trap oil and gas structures of this area at Minaluli, Madafuhi, and Lekosula are near the location of oil and gas seepage, that is propose to explore and drill in that area. Whereas in Taliabu Island, Tolong, Pena, Samuya, and Jiko Gulf still need increasing datas. Reservoir rocks consist of sandstones and limestones of Tanamu Formations were Late Cretaceous age, that occupied the location of 0 mGal to 5 mGal residual anomaly with density 2.65 g/cm ³. Hostrock are Buya Formation are Middle Jurassic - Late Jurassic from black shales with density 2.71 g/cm³, and kitchen oil were formed in the area - 4 mGal to -28 mGal residual anomaly that formed low anomaly in the northern offshore of Mangole Island. Keyword: gravity, oil kitchen, basin, oil and gas, black shales, recidual anomaly, density, anticline, hostrocks.

Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria

2016 ◽  
Author(s):  
Samuel Salufu ◽  
Rita Onolemhemhen ◽  
Sunday Isehunwa
Keyword(s):  
Case Studies ◽  
Source Rock ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Hydrocarbon Generation ◽  
Geochemical Analysis ◽  
Anambra Basin ◽  
Oil Generation

ABSTRACT This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are > 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from< 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.

Poroperm properties of reservoir rocks at Kachalivske oil and gas condensate field

2018 ◽  
pp. 18-24
Author(s):  
V. V. Fedoriv ◽  
Ya. M. Ftemov ◽  
I. O. Piatkovska ◽  
A. O. Trubenko
Keyword(s):  
Oil And Gas ◽  
Statistical Processing ◽  
Gas Condensate ◽  
Reservoir Rock ◽  
Geophysical Research ◽  
Reliable Determination ◽  
Reservoir Rocks ◽  
Experimental Laboratory ◽  
Rock Parameters

The results of laboratory, geological and geophysical research methods in Visean and Tournaisian reservoir rocks with complex type deposits of Kachalivske oil and gas condensate feild were analysed. The connection of structural and lithological characteristics with geophysical parameters was substantiated. In some cases, in the Visean and Tournaisian deposits, the multicomponent composition of the rock matrix affects the actual value of geophysical parameter, leading to erroneous conclusions about the reservoir, the nature of the saturation and depth of occurrence. As a result of the statistical processing of experimental laboratory studies and geophysical studies of wells in the Visean and Tournaisian deposits at Kachalivske oil and gas condensate feild, petrophysical models of reservoir rocks were developed allowing reliable determination of poroperm properties of such reservoir rocks. The developed models can be used both for determination the reservoir rock parameters and for quick interpretation of geophysical research results.

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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