THE SUBSURFACE GEOLOGY OF THE WESTERN OFFICER BASIN — RESULTS OF SHELL'S 1980-1984 PETROLEUM EXPLORATION CAMPAIGN

1985 ◽  
Vol 25 (1) ◽  
pp. 34 ◽  
Author(s):  
W.G. Townson
Keyword(s):  
Lower Cambrian ◽  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Gas Generation ◽  
Upper Proterozoic ◽  
Magnetic Basement ◽  
Complex Structural ◽  
Proterozoic Basement ◽  
The 1960S

The Officer Basin described in this paper includes four Proterozoic to Lower Palaeozoic sub-basins (Gibson, Yowalga, Lennis, Waigen) which extend in a northwest to southeast belt across 200 000 sq. km of central Western Australia. These sub-basins are bounded by Archaean to Proterozoic basement blocks and are almost entirely concealed by a veneer of Permian and Cretaceous sediments. Depth to magnetic basement locally exceeds eight kilometres.Until recently, information on the sub-surface geology was limited to shallow levels, based on the results of a petroleum exploration campaign in the 1960s and the work of State and Federal Geological Surveys. In 1980, the Shell Company of Australia was awarded three permits (46 200 sq. km) covering the Yowalga and Lennis Sub-basins. The results of 4700 km of seismic data and three deep wildcat wells, combined with gravity, aeromagnetic, Landsat, outcrop and corehole information, has led to a better understanding of the regional subsurface geology.The Lennis Sub-basin appears to contain Lower to Middle Proterozoic sediments, whereas the Yowalga Sub- basin is primarily an Upper Proterozoic to Lower Cambrian sequence which comprises a basal clastic section, a middle carbonate and evaporite sequence and an upper clastic section. Widespread Middle Cambrian basalts cap the Upper Proterozoic to Lower Cambrian prospective sequence. Late Proterozoic uplift resulted in salt- assisted gravity tectonics leading to complex structural styles, especially in the basin axis.Despite oil shows, organic matter in the oil and gas generation windows and reservoir-quality sandstones with interbedded shales, no convincing source rocks or hydrocarbon accumulations have yet been located. The area remains, however, one of the least explored basins in Australia.

PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

2000 ◽  
Vol 40 (1) ◽  
pp. 26
Author(s):  
M.R. Bendall C.F. Burrett ◽  
H.J. Askin
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Late Triassic ◽  
Upper Permian ◽  
Lower Permian ◽  
Peak Oil ◽  
Petroleum Systems ◽  
Upper Proterozoic ◽  
Oil Seep

Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.

Quantitative and qualitative experimental approach of oil and gas generation: Application to the North Sea source rocks

1990 ◽  
Vol 16 (1-3) ◽  
pp. 133-142 ◽  
Author(s):  
J.C. Monin ◽  
J. Connan ◽  
J.L. Oudin ◽  
B. Durand
Keyword(s):  
North Sea ◽  
Experimental Approach ◽  
Oil And Gas ◽  
Source Rocks ◽  
Gas Generation ◽  
The North ◽  
The North Sea

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.

NEW DIRECTIONS IN GEOSCIENCE TECHNOLOGY FOR PETROLEUM EXPLORATION IN THE NEW AGE

1994 ◽  
Vol 34 (1) ◽  
pp. 189
Author(s):  
T. L. Burnett
Keyword(s):  
Oil And Gas ◽  
Regional Scale ◽  
Seismic Energy ◽  
Oil And Gas Industry ◽  
Transport Processes ◽  
Source Rocks ◽  
P Wave ◽  
Petroleum Exploration ◽  
S Wave ◽  
Seismic Acquisition

As economics of the oil and gas industry become more restrictive, the need for new means of improving exploration risks and reducing expenses is becoming more acute. Partnerships between industry and academia are making significant improvements in four general areas: Seismic acquisition, reservoir characterisation, quantitative structural modelling, and geochemical inversion.In marine seismic acquisition the vertical cable concept utilises hydrophones suspended at fixed locations vertically within the water column by buoys. There are numerous advantages of vertical cable technology over conventional 3-D seismic acquisition. In a related methodology, 'Borehole Seismic', seismic energy is passed between wells and valuable information on reservoir geometry, porosity, lithology, and oil saturation is extracted from the P-wave and S-wave data.In association with seismic methods of determining the external geometry and the internal properties of a reservoir, 3-dimensional sedimentation-simulation models, based on physical, hydrologic, erosional and transport processes, are being utilised for stratigraphic analysis. In addition, powerful, 1-D, coupled reaction-transport models are being used to simulate diagenesis processes in reservoir rocks.At the regional scale, the bridging of quantitative structural concepts with seismic interpretation has led to breakthroughs in structural analysis, particularly in complex terrains. Such analyses are becoming more accurate and cost effective when tied to highly advanced, remote-sensing, multi-spectral data acquisition and image processing technology. Emerging technology in petroleum geochemistry, enables geoscientists to infer the character, age, maturity, identity and location of source rocks from crude oil characteristics ('Geochemical Inversion') and to better estimate hydrocarbon-supply volumetrics. This can be invaluable in understanding petroleum systems and in reducing exploration risks and associated expenses.

scholarly journals Burial History, Thermal Maturity, and Oil and Gas Generation History of Source Rocks in the Bighorn Basin, Wyoming and Montana

2008 ◽  
Author(s):  
Laura N.R. Roberts ◽  
Thomas M. Finn ◽  
Michael D. Lewan ◽  
Mark A. Kirschbaum
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bighorn Basin ◽  
Thermal Maturity ◽  
Burial History ◽  
Gas Generation ◽  
History Of

THE EFFECT OF INERTINITE ON KEROGEN APPRAISAL BY PROGRAMMED PYROLYSIS, NORTH WEST SHELF, AUSTRALIA

1994 ◽  
Vol 34 (1) ◽  
pp. 297
Author(s):  
E.L. Horstman
Keyword(s):  
Organic Carbon ◽  
Oil And Gas ◽  
Hydrogen Index ◽  
Source Rocks ◽  
Gas Generation ◽  
North West ◽  
The North ◽  
Measured Amount

The oil potential of rocks containing inertinite is systematically underestimated by chemical or programmed pyrolysis techniques. Inertinite is measured as organic carbon, but does not contribute to the hydrocarbons produced during pyrolysis. When maceral data is available the measured amount of organic carbon can be recalculated to establish an Hydrogen Index based only on the kerogen which might contribute to oil and gas generation. Inertiniterich rocks that were previously discounted as being only gas prone should be reviewed.Recalculated HI:OI plots prepared from samples from the North West Shelf of Australia indicate the presence of significant amounts of oil-prone kerogen in source rocks previously evaluated as being predominantly gas-prone, upgrading the oil potential of the area.

PETROLEUM SOURCE ROCKS IN THE ROPER GROUP OF THE MCARTHUR BASIN: SOURCE CHARACTERISATION AND MATURITY DETERMINATIONS USING PHYSICAL AND CHEMICAL METHODS

1994 ◽  
Vol 34 (1) ◽  
pp. 279 ◽  
Author(s):  
Dennis Taylor ◽  
Aleksai E. Kontorovich ◽  
Andrei I. Larichev ◽  
Miryam Glikson
Keyword(s):  
Organic Matter ◽  
Chemical Evolution ◽  
Oil And Gas ◽  
Source Rocks ◽  
Type I ◽  
Peak Oil ◽  
Gas Generation ◽  
Oil Generation ◽  
Physical And Chemical ◽  
Extractable Organic Matter

Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.

scholarly journals Basic characteristics and accumulation mechanism of Sinian−Cambrian giant highly mature and oil-cracking gas reservoirs in the Sichuan Basin, SW China

2017 ◽  
Vol 36 (4) ◽  
pp. 568-590 ◽  
Author(s):  
Bing Luo ◽  
Yu Yang ◽  
Gang Zhou ◽  
Wenjun Luo ◽  
Shujiao Shan ◽  
...  
Keyword(s):  
Natural Gas ◽  
Lower Cambrian ◽  
Sichuan Basin ◽  
Large Scale ◽  
Oil And Gas ◽  
Source Rocks ◽  
Burial Depth ◽  
Sw China ◽  
Accumulation Mechanism ◽  
Oil Cracking

Old Mesoproterozoic−Cambrian successions have been regarded as an important frontier field for global oil and gas exploration in the 21st century. This has been confirmed by a recent natural gas exploration breakthrough in the Sinian and Cambrian strata, central Sichuan Uplift, Sichuan Basin of SW China. However, the accumulation mechanism and enrichment rule of these gases have not been well characterized. This was addressed in this work, with aims to provide important guidance for the further exploration while enriching the general studies of the oil and gas geology in the old Mesoproterozoic–Cambrian strata. Results show that the gas field in the study area is featured by old target layers (Sinian–Lower Cambrian), large burial depth (>4500 m), multiple gas-bearing intervals (the second and fourth members of the Sinian Dengying Formation and the Lower Cambrian Longwangmiao Formation), various gas reservoir types (structural type and structural–lithologic type), large scale (giant), and superimposing and ubiquitous distribution. The giant reserves could be attributed to the extensive intercalation of pervasive high quality source rocks and large-scale karst reservoirs, which enables a three-dimensional hydrocarbon migration and accumulation pattern. The origin of natural gas is oil cracking, and the three critical stages of accumulation include the formation of oil reservoirs in Triassic, the cracking of oil in Cretaceous, and the adjustment and reaccumulations in the Paleogene. The main controlling factor of oil and gas enrichment is the inherited development of large-scale stable paleo-uplift, and the high points in the eastern paleo-uplift are the favorable area for ​natural gas exploration.

scholarly journals Accommodation zones and tectono-stratigraphy of the Gulf of Suez, Egypt: A contribution from aeromagnetic analysis

GeoArabia ◽  
2009 ◽  
Vol 14 (4) ◽  
pp. 139-162
Author(s):  
Khamis Farhoud
Keyword(s):  
Three Dimensional ◽  
Source Rocks ◽  
Gulf Of Suez ◽  
Rift Basins ◽  
Early Oligocene ◽  
Accommodation Zone ◽  
Magnetic Basement ◽  
Petroleum Fields ◽  
Proterozoic Basement ◽  
Seismic Images

ABSTRACT This paper starts with an up-to-date literature review of the pre-rift, syn-rift and post-rift stratigraphy of the Gulf of Suez. The geometry and depth of the Proterozoic basement is not generally known due to poor seismic images below the Upper Miocene evaporites (including massive rock salt) and clastics. The pre-rift Paleozoic to Early Oligocene succession shows that several local basins (c. 10s of km in extent) occur in the Gulf, with thick sedimentary sections (e.g. c. 3,000 m for Paleozoic and 1,000 m for Jurassic and Lower Cretaceous). The origin and distribution of these basins is not well understood and the presence of similar pre-rift basins in the southern Gulf is not known to occur. The syn-rift Late Oligocene to Middle Miocene and post-rift Late Miocene – Pliocene successions are widely distributed within the rift basin and reach a thickness in excess of 5,000 m. In order to visualize the grain and relative relief of the Proterozoic basement, a series of aeromagnetic images are shown in this paper. The images include Total Magnetic Intensity (TMI), Reduced-to-Pole (RTP), filtered regional and structural RTP, and Second Vertical Derivative (SVD). The paper also shows a three-dimensional visualization image of the magnetic basement that highlights the distribution of the basins in the Gulf. The magnetic lows do not generally trend along the Suez (NNW-trending Clysmic) Fault, but instead show highly variable orientations attributed to a complex pattern of criss-crossing faults. In particular, two areas were selected to interpret the geometry and depth of the basement. The first area covered the northern Zaafarana Accommodation Zone and involved modeling five aeromagnetic profiles. The Zone was interpreted as an EW-trending basement plateau bounded by basins that are c. 8,000 m deep. The second modeled area (four profiles) covered the southern Morgan Accommodation Zone. This zone was interpreted as an ENE-trending plateau of similar relief to the Zaafarana Zone. The Morgan Zone is terminated in the eastern Gulf by the 8,000-m-deep Morgan Basin. The very deep basins surrounding the two plateaus may contain both pre-rift and syn-rift source rocks, from which the numerous surrounding petroleum fields were sourced.

scholarly journals Early Paleozoic Extension-Compression Transition and Formation of a Paleo-Oil Reservoir System in the NW Sichuan Basin: Implications for Deeply Buried Hydrocarbon Accumulation

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-25
Author(s):  
Xiao Liang ◽  
Shu-gen Liu ◽  
Liang-liang Wu ◽  
Bin Deng ◽  
Jing Li ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Late Triassic ◽  
Oil Reservoir ◽  
Hydrocarbon Accumulation ◽  
Early Paleozoic ◽  
Gas Generation ◽  
Western Sichuan ◽  
Marine Strata ◽  
Complex Structural ◽  
Hydrocarbon Distribution

Owing to multiple tectonic events after the Late Triassic, the northern segment of the western Sichuan depression (NSWSCD) has a complex geological history of significant uplift and deeply buried. With abundant oil and gas play in the NSWSCD, the study of paleo-oil reservoir systems and early hydrocarbon accumulation in this area is of great significance for deep marine hydrocarbon distribution prediction in complex structural settings. Analysis on the northern section of the Mianyang-Changning Intracratonic Sag (MY-CN IS) and the Tianjingshan Paleouplift (TJS PU), the two Early Paleozoic tectonic units are laterally superimposed. Combined the reservoir bitumen of the Sinian Dengying Fm firstly, the biomarker (TT23/tT24, S21/S22, etc.) and Organic δ13C (lighter than 30‰) characteristics indicate that the Sinian-Jurassic paleo-oil system in the TJS PU area is the main source of Lower Cambrian organic-rich black shale. This is closely related to the superimposition and combination effects of the intracratonic sag and paleouplift. Therefore, this study establishes a geological-geochemical accumulation model through a combination of R o and fluid inclusion data. The No. 1 fault is an important zoning fault in the NSWSCD, which significantly controls the division of the oil-gas zone. The process of paleo-oil reservoir destroyed directly only exists in the frontal deformation zone. The deep marine strata of the eastern No. 1 fault demonstrate the four-center hydrocarbon accumulation processes, which include oil generation, gas generation, gas storage, and gas preservation. The superdeep Dengying Fm has long-term exploration potential in the NSWSCD.

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