Research for the Upstream Petroleum Sector: The Crown Research Institute Concept

1995 ◽  
Vol 13 (2-3) ◽  
pp. 245-252
Author(s):  
J M Beggs
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Publicly Funded ◽  
Petroleum Systems ◽  
Oil And Gas Resources ◽  
Petroleum Sector ◽  
Geological Sciences ◽  
Research Institute

New Zealand's scientific institutions have been restructured so as to be more responsive to the needs of the economy. Exploration for and development of oil and gas resources depend heavily on the geological sciences. In New Zealand, these activities are favoured by a comprehensive, open-file database of the results of previous work, and by a historically publicly funded, in-depth knowledge base of the extensive sedimentary basins. This expertise is now only partially funded by government research contracts, and increasingly undertakes contract work in a range of scientific services to the upstream petroleum sector, both in New Zealand and overseas. By aligning government-funded research programmes with the industry's knowledge needs, there is maximum advantage in improving the understanding of the occurrence of oil and gas resources. A Crown Research Institute can serve as an interface between advances in fundamental geological sciences, and the practical needs of the industry. Current publicly funded programmes of the Institute of Geological and Nuclear Sciences include a series of regional basin studies, nearing completion; and multi-disciplinary team studies related to the various elements of the petroleum systems of New Zealand: source rocks and their maturation, migration and entrapment as a function of basin structure and tectonics, and the distribution and configuration of reservoir systems.

scholarly journals SEPARATE QUANTITATIVE PREDICTION OF OIL AND GAS CONTENT PROSPECTS FOR DZHEBOL STAGE PALEOZOIC DEPOSITS OF TIMAN-PECHORA OIL AND GAS BASIN

2015 ◽  
pp. 9-15
Author(s):  
A. I. Diyakonov ◽  
L. V. Parmuzina ◽  
S. V. Kochetov ◽  
A. Yu. Malikova
Keyword(s):  
Oil And Gas ◽  
Sedimentary Basin ◽  
Scientific Basis ◽  
Source Rocks ◽  
Gas Content ◽  
Quantitative Prediction ◽  
Oil And Gas Resources ◽  
Gas Bearing

It is shown that the evolutionary-catagenetic model for calculating the initial potential hydrocarbon resources can serve as a scientific basis for the separate quantitative prediction of areas of oil-and-gas content. In this case retrospectively evaluated are the scales of generation and accumulation of hydrocarbons in the source rocks during catagenetic evolution of sedimentary basin. The authors propose a method, the results of evaluation of generation and accumulation scales and initial potential oil and gas resources for major oil-and-gas bearing complexes of Dzhebol stage.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

Resolving thermal histories via multi-kinetic apatite fission track data: A case study from Phanerozoic strata within the Peel Plateau NWT, Canada

2021 ◽  
Author(s):  
Jennifer Spalding ◽  
Jeremy Powell ◽  
David Schneider ◽  
Karen Fallas
Keyword(s):  
Low Temperature ◽  
Thermal History ◽  
Fission Track ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Apatite Fission Track ◽  
Petroleum Systems ◽  
History Of ◽  
Thermal Histories ◽  
Peel Plateau

&lt;p&gt;Resolving the thermal history of sedimentary basins through geological time is essential when evaluating the maturity of source rocks within petroleum systems. Traditional methods used to estimate maximum burial temperatures in prospective sedimentary basin such as and vitrinite reflectance (%Ro) are unable to constrain the timing and duration of thermal events. In comparison, low-temperature thermochronology methods, such as apatite fission track thermochronology (AFT), can resolve detailed thermal histories within a temperature range corresponding to oil and gas generation. In the Peel Plateau of the Northwest Territories, Canada, Phanerozoic sedimentary strata exhibit oil-stained outcrops, gas seeps, and bitumen occurrences. Presently, the timing of hydrocarbon maturation events are poorly constrained, as a regional unconformity at the base of Cretaceous foreland basin strata indicates that underlying Devonian source rocks may have undergone a burial and unroofing event prior to the Cretaceous. Published organic thermal maturity values from wells within the study area range from 1.59 and 2.46 %Ro for Devonian strata and 0.54 and 1.83 %Ro within Lower Cretaceous strata. Herein, we have resolved the thermal history of the Peel Plateau through multi-kinetic AFT thermochronology. Three samples from Upper Devonian, Lower Cretaceous and Upper Cretaceous strata have pooled AFT ages of 61.0 &amp;#177; 5.1 Ma, 59.5 &amp;#177; 5.2 and 101.6 &amp;#177; 6.7 Ma, respectively, and corresponding U-Pb ages of 497.4 &amp;#177; 17.5 Ma (MSWD: 7.4), 353.5 &amp;#177; 13.5 Ma (MSWD: 3.1) and 261.2 &amp;#177; 8.5 Ma (MSWD: 5.9). All AFT data fail the &amp;#967;&lt;sup&gt;2&lt;/sup&gt; test, suggesting AFT ages do not comprise a single statistically significant population, whereas U-Pb ages reflect the pre-depositional history of the samples and are likely from various provenances. Apatite chemistry is known to control the temperature and rates at which fission tracks undergo thermal annealing. The r&lt;sub&gt;mro&lt;/sub&gt; parameter uses grain specific chemistry to predict apatite&amp;#8217;s kinetic behaviour and is used to identify kinetic populations within samples. Grain chemistry was measured via electron microprobe analysis to derive r&lt;sub&gt;mro&lt;/sub&gt; values and each sample was separated into two kinetic populations that pass the &amp;#967;&lt;sup&gt;2&lt;/sup&gt; test: a less retentive population with ages ranging from 49.3 &amp;#177; 9.3 Ma to 36.4 &amp;#177; 4.7 Ma, and a more retentive population with ages ranging from 157.7 &amp;#177; 19 Ma to 103.3 &amp;#177; 11.8 Ma, with r&lt;sub&gt;mr0&lt;/sub&gt; benchmarks ranging from 0.79 and 0.82. Thermal history models reveal Devonian strata reached maximum burial temperatures (~165&amp;#176;C-185&amp;#176;C) prior to late Paleozoic to Mesozoic unroofing, and reheated to lower temperatures (~75&amp;#176;C-110&amp;#176;C) in the Late Cretaceous to Paleogene. Both Cretaceous samples record maximum burial temperatures (75&amp;#176;C-95&amp;#176;C) also during the Late Cretaceous to Paleogene. These new data indicate that Devonian source rocks matured prior to deposition of Cretaceous strata and that subsequent burial and heating during the Cretaceous to Paleogene was limited to the low-temperature threshold of the oil window. Integrating multi-kinetic AFT data with traditional methods in petroleum geosciences can help unravel complex thermal histories of sedimentary basins. Applying these methods elsewhere can improve the characterisation of petroleum systems.&lt;/p&gt;

Anabar-Lena Composite Tectono-Sedimentary Element, Northern East Siberia

2021 ◽  
pp. M57-2021-29
Author(s):  
A.K. Khudoley ◽  
S.V. Frolov ◽  
G.G. Akhmanov ◽  
E.A. Bakay ◽  
S.S. Drachev ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Foreland Basin ◽  
Early Carboniferous ◽  
Passive Margin ◽  
Source Rocks ◽  
East Siberia ◽  
Lena River ◽  
Petroleum Systems ◽  
Intracratonic Basin

AbstractAnabar-Lena Composite Tectono-Sedimentary Element (AL CTSE) is located in the northern East Siberia extending for c. 700 km along the Laptev Sea coast between the Khatanga Bay and Lena River delta. AL CTSE consists of rocks from Mesoproterozoic to Late Cretaceous in age with total thickness reaching 14 km. It evolved through the following tectonic settings: (1) Meso-Early Neoproterozoic intracratonic basin, (2) Ediacaran - Early Devonian passive margin, (3) Middle Devonian - Early Carboniferous rift, (4) late Early Carboniferous - latest Jurassic passive margin, (5) Permian foreland basin, (6) Triassic to Jurassic continental platform basin and (7) latest Jurassic - earliest Late Cretaceous foreland basin. Proterozoic and lower-middle Paleozoic successions are composed mainly by carbonate rocks while siliciclastic rocks dominate upper Paleozoic and Mesozoic sections. Several petroleum systems are assumed in the AL CTSE. Permian source rocks and Triassic sandstone reservoirs are the most important play elements. Presence of several mature source rock units and abundant oil- and gas-shows (both in wells and in outcrops), including a giant Olenek Bitumen Field, suggest that further exploration in this area may result in economic discoveries.

NEW PETROLEUM MODELS IN THE PEDIRKA BASIN, NORTHERN TERRITORY, AUSTRALIA

2002 ◽  
Vol 42 (1) ◽  
pp. 259 ◽  
Author(s):  
G.J. Ambrose ◽  
K. Liu ◽  
I. Deighton ◽  
P.J. Eadington ◽  
C.J. Boreham
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
Sedimentary Basins ◽  
Poor Quality ◽  
Northern Territory ◽  
Early Jurassic ◽  
Source Rocks ◽  
Late Triassic ◽  
Hydrocarbon Expulsion ◽  
Migration Pathways

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2,500 km of seismic data occur over a prospective area of 73,000 km2 which comprises three stacked sedimentary basins of Palaeozoic to Mesozoic age. In this area three petroleum systems have potential related to important source intervals in the Early Jurassic Eromanga Basin (Poolowanna Formation), the Triassic Simpson Basin (Peera Peera Formation) and Early Permian Pedirka Basin (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. Basin modelling using modern techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time, when source rocks entered the wet gas maturation window.The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone equivalent, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/Tirrawarra petroleum system found in the Cooper Basin.An integrated investigation into the hydrocarbon charge and migration history of Colson–1 was carried out using CSIRO Petroleum’s OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the Early Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone equivalent. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin.Conventional structural targets are numerous, but the timing of hydrocarbon expulsion dictates that those with an older drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source kitchens on relatively short migration pathways. Early formed stratigraphic traps at the level of the Tirrawarra Sandstone equivalent and Poolowanna Formation are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir–seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.

COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

2003 ◽  
Vol 43 (1) ◽  
pp. 117 ◽  
Author(s):  
C.J. Boreham ◽  
J.E. Blevin ◽  
A.P. Radlinski ◽  
K.R. Trigg
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Middle Eocene ◽  
Vitrinite Reflectance ◽  
Mineral Resources ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Gas Generation ◽  
Australian Context ◽  
Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

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.

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