Seeing through the dolerite-seismic imaging of petroleum systems, Tasmania, Australia

2015 ◽  
Vol 55 (1) ◽  
pp. 297
Author(s):  
Malcolm Bendall ◽  
Clive Burrett ◽  
Paul Heath ◽  
Andrew Stacey ◽  
Enzo Zappaterra
Keyword(s):  
Seismic Energy ◽  
Petroleum System ◽  
Source Rocks ◽  
Contact Metamorphism ◽  
Seismic Surveys ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Potential Reservoir ◽  
Frequency Sweeps ◽  
The Many

Prior to the onshore work of Empire Energy Corporation International (Empire) it was widely believed that the widespread sheets (>650 m thick) of Jurassic dolerite (diabase) would not only have destroyed the many potential petroleum source and reservoir rocks in the basin but would also absorb seismic energy and would be impossible to drill. By using innovative acquisition parameters, however, major and minor structures and formations can be identified on the 1,149 km of 2D Vibroseis. Four Vibroseis trucks were used with a frequency range of 6–140 Hz with full frequency sweeps close together, thereby achieving maximum input and return signal. Potential reservoir and source rocks may be seismically mapped within the Gondwanan Petroleum System (GPS) of the Carboniferous to Triassic Parmeener Supergroup in the Tasmania Basin. Evidence for a working GPS is from a seep of migrated, Tasmanite-sourced, heavy crude oil in fractured dolerite and an oil-bearing breached reservoir in Permian siliciclastics. Empire’s wells show that each dolerite sheet consists of several intrusive units and that contact metamorphism is usually restricted to within 70 m of the sheets’ lower margins. In places, there are two thick sheets, as on Bruny Island. One near-continuous 6,500 km2 sheet is mapped seismically across central Tasmania and is expected, along with widespread Permian mudstones, to have acted as an excellent regional seal. The highly irregular pre-Parmeener unconformity can be mapped across Tasmania and large anticlines (Bellevue and Thunderbolt prospects and Derwent Bridge Anticline) and probable reefs can be seismically mapped beneath this unconformity within the Ordovician Larapintine Petroleum System. Two independent calculations of mean undiscovered potential (or prospective) resources in structures defined so far by Empire’s seismic surveys are 596.9 MMBOE (millions of barrels of oil equivalent) and 668.8 MMBOE.

scholarly journals ADVANCES ON THE GEOLOGY AND EVALUATION OF POTENTIAL PETROLEUM SYSTEMS OF THE SOKOTO BASIN IN NW NIGERIA

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Current Knowledge ◽  
Petroleum System ◽  
Source Rocks ◽  
Tectonic Structures ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Potential Reservoir ◽  
Geochemical Studies ◽  
Controlled Structures

The stratigraphy of the Sokoto Basin has the Illo/Gundumi Formation at the bottom, followed successively upward by the Taloka, Dukamaje, Wurno, Dange, Kalambaina, Gamba and Gwandu Formations. Re-mapping of the basin carried out in this study shows that the geological framework remains largely as previously outlined except that some hitherto unreported tectonically controlled structures have been documented. The basin is generally shallower at the margin and deepens towards the centre such that the areas around the border with Niger Republic are deepest and hence most prospective on the Nigerian side. Geophysical aeromagnetic interpretation has assisted to analyze the depth to basement configurations. Organic geochemical studies show that the dark shales and limestones of the Dukamaje Formation constitute the source rocks in the potential petroleum system. With averages for source rock thickness of 50m, area of basin of 60,000km2, TOC of 7.5wt%, and HI of 212mgHC/gTOC, charge modeling indicates 808.10 million barrels of oil equivalent extractable hydrocarbons in the Sokoto Basin, at current knowledge of the geology and if the appropriate maturity has been attained at deeper sections. The sandstones of the Illo/Gundumi Formation as well as in the Taloka and Wurno Formations and carbonates of the Kalambaina Formation provide potential reservoir packages. The paper shale of the Gamba Formation and the clays of the Gwandu Formation provide regional seals. If the presently mapped tectonic structures are ubiquitous in the whole basin, structural and stratigraphic traps may upgrade the petroleum system. Other petroleum systems may exist in the basin with either or both the Illo/Gundumi and Taloka Formation(s) providing the source and reservoir rocks. Keywords: Sokoto Basin, Dukamaje Formation, Hydrocarbons, Petroleum System, Reservoirs

scholarly journals The Cambrian Henson Gletscher Formation: a mature to postmature hydrocarbon source rock sequence from North Greenland

1987 ◽  
Vol 133 ◽  
pp. 141-157
Author(s):  
F.G Christiansen ◽  
H Nøhr-Hansen ◽  
O Nykjær
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Potential Reservoir ◽  
Field Season ◽  
North Greenland

During the 1985 field season the Cambrian Henson Gletscher Formation in central North Greenland was studied in detail with the aim of evaluating its potential as a hydrocarbon source rock. The formation contains organic rich shale and carbonate mudstone which are considered to be potential source rocks. These are sedimentologically coupled with a sequence of sandstones and coarse carbonates which might be potential reservoir rocks or migration conduits. Most of the rocks exposed on the surface are, however, thermally mature to postrnature with respect to hydrocarbon generation, leaving only few chances of finding trapped oil in the subsurface of the area studied in detail.

Petroleum systems and results of exploration on the Atlantic margins of the UK, Faroes & Ireland: what have we learnt?

2016 ◽  
Vol 8 (1) ◽  
pp. 187-197 ◽  
Author(s):  
Iain C. Scotchman ◽  
Anthony G. Doré ◽  
Anthony M. Spencer
Keyword(s):  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Gas Field ◽  
Petroleum Systems ◽  
Unknown Source ◽  
Porcupine Basin ◽  
Break Up ◽  
Northern North Sea ◽  
The Uk

AbstractThe exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×109 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×109 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

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.

THE CAMBRIAN PALAEOGEOGRAPHY OF AUSTRALIA AND OPPORTUNITIES FOR PETROLEUM EXPLORATION

1982 ◽  
Vol 22 (1) ◽  
pp. 42 ◽  
Author(s):  
Peter J. Cook
Keyword(s):  
Continental Drift ◽  
Depositional Environments ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Time Intervals ◽  
Middle Cambrian ◽  
Reservoir Rocks ◽  
Essential Components ◽  
Potential Reservoir ◽  
Cooper Basin

As part of a larger project to re-evaluate the petroleum potential of Australia, it was considered necessary to produce a series of Cambrian palaeogeographic maps. This required the compilation and correlation of a large number of stratigraphic columns, the delineation of sedimentologlcally-significant time intervals, the production of data maps for these same time intervals, and the development of a Cambrian 'tectonic' map. This palaeogeographic study was not undertaken to establish precise exploration targets. However, it does provide new information on where many of the essential components are, what age they are, and why they are there, and as such is a valuable tool in the overall exploration and resource evaluation strategy.The six palaeogeographic maps finally produced illustrate events involving continental drift, tectonics, and climatic and sea-level variations, over a period of 70 million years. Together, these events produced marked changes in the palaeogeography and depositional environments, which in turn profoundly affected the type and distribution of sediments being deposited on and around the palaeo-continent during the Cambrian. Using the palaeogeographic maps and the data accumulated for the project, it is possible to demonstrate that organic-rich sediments, with the potential to be petroleum source rocks, were relatively common during the Cambrian, especially on the eastern cratonic margin during the Lower Cambrian (Officer and possible Amadeus Basins) and the Middle Cambrian (Georgina Basin). There may also be some suitable petroleum source rocks in the Ord Basin. Limestones and dolomites, some of which may constitute potential reservoir rocks, were deposited in a number of Cambrian intracratonic basins (Amadeus, Georgina Basins) and on the shelf (Cooper Basin). Cambrian sandstones in Australia are commonly poor reservoir rocks, but where they have been subjected to shore-line or shelf 'clean-up', for example during the Middle and Upper Cambrian on the northwest side of the craton (Bonaparte Gulf Basin), there may be some potential reservoir rocks. Some sandstones may also be present on the south side of the Cooper Basin. Fine-grained impermeable sediments (potential cap rocks) were deposited throughout the Cambrian, but evaporites were most common during the Early and lower Middle Cambrian. Synsedimentary tectonics may have produced structural and stratigraphlc traps, and a major phase of karsting occurred in the Cambrian. Therefore, the Cambrian of Australia is believed to have many of the prerequisites for the generation, migration and entrapment of hydrocarbons. Especially favourable areas for these features may lie to the southeast of the Georgina Basin and in the offshore region northwest of the Ord and Bonaparte Gulf Basins.

A reassessment of the petroleum systems in the offshore northern Perth Basin

2013 ◽  
Vol 53 (2) ◽  
pp. 427
Author(s):  
Emmanuelle Grosjean ◽  
Chris Boreham ◽  
Andrew Jones ◽  
Diane Jorgensen ◽  
John Kennard
Keyword(s):  
Primary Source ◽  
Petroleum System ◽  
Source Rocks ◽  
Early Triassic ◽  
Widespread Occurrence ◽  
Petroleum Systems ◽  
Oil Generation ◽  
History Of ◽  
Effective Source ◽  
Commercial Oil

The discovery of commercial oil in the Cliff Head-1 well in 2001 set an important milestone in the exploration history of the offshore northern Perth Basin. The region had been less explored before then, partly due to the perception that the main source of onshore petroleum accumulations, the Late Permian-Early Triassic Hovea Member, had only marginal potential offshore. The typing of the Cliff Head oil to the Hovea Member provided evidence that the key onshore petroleum system extends offshore and has revitalised exploration with 13 new field wildcat wells drilled since 2002. A reassessment of the hydrocarbon generative potential in the offshore northern Perth Basin confirms the widespread occurrence of good to excellent oil-prone Hovea Member source rocks in the Beagle Ridge and Abrolhos Sub-basin. The Early Permian Irwin River Sequence and several Jurassic Sequences are also recognised as prime potential source rocks offshore, mostly for their gas-generative potential. The unique hydrocarbon assemblages exhibited by the Hovea Member extracts are shared by the oils recovered from Permian reservoirs in the offshore Cliff Head-3 and Dunsborough-1 wells, indicating the Hovea Member as the primary source charging these accumulations. Geochemical correlation of oil stains from Hadda-1 and as far north as Livet-1 provides evidence for a working Early Triassic petroleum system across much of the Abrolhos Sub-basin. In this area, the Hovea Member was shown to be both of limited quality and only marginally mature for oil generation, which suggests the occurrence of effective source kitchens in the adjacent Houtman Sub-basin.

GEOCHEMICAL CHARACTERISTICS OF AUSTRALIA'S SOUTHERN MARGIN PETROLEUM SYSTEMS

1999 ◽  
Vol 39 (1) ◽  
pp. 297 ◽  
Author(s):  
D.S. Edwards ◽  
H.I.M. Struckmeyer ◽  
M.T. Bradshaw ◽  
J.E. Skinner
Keyword(s):  
Upper Cretaceous ◽  
Petroleum System ◽  
Geochemical Characteristics ◽  
Source Rocks ◽  
Liquid Hydrocarbons ◽  
Petroleum Systems ◽  
Tectonic History ◽  
Southern Margin ◽  
History Of ◽  
Oil Source

The hydrocarbons discovered to date on the southern margin of Australia have been assigned to the Austral Petroleum Supersystem based on the age of their source rocks and common tectonic history. Modelling of the source facies distribution within this supersystem using tectonic, climatic and geographic history of the southern margin basins, suggests the presence of a variety of source rocks deposited in saline playa lakes, fluvial, lacustrine, deltaic and anoxic marine environments.Testing of the palaeogeographic model using geochemical characteristics of liquid hydrocarbons confirms the three-fold subdivision (Al, A2 and A3) of the Austral Petroleum Supersystem.Bass Basin oils are assigned to the Austral 3, Eastern View Petroleum System. The presence of oleanane in the biomarker assemblages of these oils, together with their negatively sloping, heavy, isotopic profiles, indicate derivation from Upper Cretaceous-Tertiary fluvio–deltaic source facies.In the eastern Otway Basin, oils of the Austral 2, Eumeralla Petroleum System are sourced by Lower Cretaceous (Aptian–Albian) coaly facies. Oil shows reservoired in the Wigunda Formation at Greenly-1 in the Duntroon Basin are possibly sourced from the Borda Formation and are assigned to the Austral 2, Borda Petroleum System.In the western Otway, Duntroon and Bight basins, a lack of definitive oil-source rock correlations precludes the identification of individual Austral 1 petroleum systems.

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

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

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

GEOCHEMICAL CHARACTERISTICS OF PALAEOZOIC PETROLEUM SYSTEMS IN NORTHWESTERN AUSTRALIA

1997 ◽  
Vol 37 (1) ◽  
pp. 351 ◽  
Author(s):  
D.S. Edwards ◽  
R.E. Summons ◽  
J.M. Kennard ◽  
R.S. Nicoll ◽  
J. Bradshaw ◽  
...  
Keyword(s):  
Fault Zone ◽  
Carbon Number ◽  
Isotopic Signature ◽  
Petroleum System ◽  
Upper Devonian ◽  
Source Rocks ◽  
Canning Basin ◽  
Petroleum Systems ◽  
Northwestern Australia ◽  
Biomarker Signature

Isotopic and biomarker analyses carried out on Cambrian to Permian oils and source rocks in the Arafura, Bonaparte (Petrel Sub-basin) and Canning Basins have been used to geochemically characterise five distinct petroleum systems within the Larapintine and Gondwanan Petroleum Supersystems. The Larapintine 1 Petroleum System is characterised by isotopically light, free hydrocarbons in the Arafura Basin (613Csat = −32 %o Arafura-1) which have been correlated to kerogens of similar isotopic signature within the Middle Cambrian Jigaimara Formation. The richness and maturity of these source rocks indicate that an effective Larapintine 1 Petroleum System may exist in the northern parts of the Arafura Basin. Larapintine 2 oils, with Gloeocapsomorpha prisca-type signatures, are found on the Barbwire- Dampier Terraces and Admiral Bay Fault Zone in the Canning Basin. These oils can be correlated to source rocks in the Lower Ordovician Goldwyer Formation on the Barbwire Terrace and the Bongabinni Formation in the Admiral Bay Fault Zone by their diagnostic odd- carbon-number preference in the C15—CJ9 n-alkanes. Larapintine 3 oils are derived from Upper Devonian marine carbonates in the Canning Basin and Petrel Sub- basin and have a diagnostic biomarker signature which includes a predominance of steranes relative to diasteranes and abundant gammacerane and 30- norhopanes, similar to those observed in the Upper Devonian Gogo and Pillara Formations. Larapintine 4 oils are derived from Lower Carboniferous marine, clay- rich mudstones in both the Petrel Sub-basin and Canning Basin. They are isotopically light (mean δ13C sat = −28 %o) and have a unique terpane signature which has been identified within the Milligans Formation. Gondwanan 1 Petroleum System hydrocarbons, represented here by the Petrel-4 condensate, have a heavy isotopic signature (δ13C sat = −24 %o) which, coupled with an abundance of the diasterane and diahopane biomarkers, indicates derivation from Permian deltaic source facies. Recognition of the diagnostic geochemical components of each Palaeozoic petroleum system has led to the identification of Permian-like isotopic signatres in some hydrocabon accumulations in the Timor Sea that were previously attributed to Mesozoic sources.

scholarly journals The hydrocarbon prospectivity of the Mesoproterozoic–Paleozoic intracratonic Voltaian Basin, West African Craton, Ghana

2020 ◽  
Author(s):  
Mahamuda Abu ◽  
Mutiu Adesina Adeleye ◽  
Olugbenga Ajayi Ehinola ◽  
Daniel Kwadwo Asiedu
Keyword(s):  
Sedimentary Basins ◽  
Depositional Environments ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
West African Craton ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
World Class ◽  
Geological Event ◽  
Oil Gas

Abstract Neoproterozoic sedimentary basins are increasingly gaining hydrocarbon exploration attention globally following results of significant discoveries in these basins as a result of long, consistent and focused research and exploration efforts. The hydrocarbon prospectivity of the unexplored Mesoproterozoic–Early Paleozoic Voltaian basin is reviewed relative to global Neoproterozoic basins. Like the Voltaian basin of Ghana, global Neoproterozoic basins have experienced similar geological event of glaciation with accompanying deposition of marginal–shallow marine carbonates and associated siliciclastic argillaceous sediments. These carbonates and argillaceous sediments coupled with deep anoxic depositional environments, favored the preservation of organic matter in these sediments and carbonates globally making them source rocks and in some cases the reservoir rocks as well, to hydrocarbon occurrence. The hydrocarbon prospectivity of the Voltaian is highly probable with Neoproterozoic basins of similar geologic analogies, Amadeus basin, Illizi basin, the Tindouf and Taoudeni basins of the WAC, having proven and active petroleum systems with some listed as world class oil/gas producing basins together with other Neoproterozoic basins like South Salt Oman basin, Barnett shales and giant gas reserves of southwestern Sichuan basin of China.

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