JURASSIC PETROLEUM SYSTEMS IN THE HOUTMAN SUB-BASIN, NORTHWESTERN OFFSHORE PERTH BASIN, WESTERN AUSTRALIA: A FRONTIER PETROLEUM PROVINCE ON THE DOORSTEP?

2004 ◽  
Vol 44 (1) ◽  
pp. 13 ◽  
Author(s):  
J.D. Gorter ◽  
D.J. Hearty ◽  
A.J. Bond
Keyword(s):  
Late Jurassic ◽  
Source Rocks ◽  
Disappointing Result ◽  
Oil Migration ◽  
Petroleum Systems ◽  
Oil Reserves ◽  
Southwestern Australia ◽  
Seismic Acquisition ◽  
Reservoir Sandstones ◽  
Coal Measures

The under-explored Houtman Sub-basin, a northwestern offshore extension of the hydrocarbon-productive Perth Basin of southwestern Australia, formed during Jurassic rifting of Gondwana. The sub-basin contains the ingredients for an exciting frontier petroleum province with typical rift architecture. Permian, Triassic and Jurassic petroleum systems are proven from the onshore region, with a productive Triassic-sourced hydrocarbon system recently demonstrated in the adjacent Abrolhos Sub-basin by the Cliff Head oil discovery, and several basal Triassic-sourced oil shows. Gas and oil shows from the Early to Middle Jurassic Cattamarra Coal Measures in Houtman–1, the only well drilled in the 32,000 km2 Houtman Sub-basin, are most likely sourced from the organic-rich Cattamarra Coal Measures and are sealed by intraformational shales and the overlying regional marine shale of the Cadda Formation. The disappointing result of Houtman–1 has coloured perceptions of the prospectivity of the Houtman Sub-basin. Despite this negativity, recent seismic acquisition and reprocessing have demonstrated the presence of large structural closures in the sub-basin that could contain substantial oil reserves as indicated by geochemical modelling of the Cattamarra Coal Measures source rocks. Analyses on GOI indicate a palaeo-oil zone at the top of the Cattamarra Coal Measures in Houtman–1 indicating that the gas-prone perception may not be true. QGF intensities from Houtman–1 suggest oil migration in sandstones beneath intra-formational seals in both the Late Jurassic Yarragadee Formation and the Cattamarra Coal Measures. In addition to reservoir sandstones, source rock intervals occur in the lower Yarragadee Formation, but regional sealing units in this formation are to be confirmed.

THE OFFSHORE CARPENTARIA BASIN-GULF OF CARPENTARIA, NORTH QUEENSLAND

1994 ◽  
Vol 34 (1) ◽  
pp. 614
Author(s):  
B.A. McConachie ◽  
P.W. Stainton ◽  
M.G. Barlow ◽  
J.N. Dunster
Keyword(s):  
Early Cretaceous ◽  
Seismic Data ◽  
Late Jurassic ◽  
Source Rocks ◽  
Low Velocity ◽  
Reservoir Rocks ◽  
Half Graben ◽  
Reservoir Sandstones ◽  
Cape York ◽  
Velocity Channel

The Carpentaria Basin is late Jurassic to early Cretaceous in age and underlies most of the Gulf of Carpentaria and surrounding onshore areas. The Carpentaria Basin is stratigraphically equivalent to the Eromanga and Papuan Basins where similar reservoir rocks produce large volumes of hydrocarbons.Drillholes Duyken–1, Jackie Ck–1 and 307RD12 provide regional lithostratigraphic and tectonic control for the Q22P permit in the offshore Carpentaria Basin. Duyken–1 penetrated the upper seal section in the Carpentaria Basin and a full sequence through the overlying Karumba Basin. Jackin Ck–1 intersected the lower reservoir units and a condensed upper seal section of the Carpentaria Basin. Coal drillhole 307RD12 tested the late Jurassic to early Cretaceous reservoir section in the Carpentaria Basin and also intersected an underlying Permian infrabasin sequence.Little is known of the pre Jurassic sedimentary section below the offshore Carpentaria Basin but at least two different rock packages appear to be present. The most encouraging are relatively small, layered, low velocity, channel and half-graben fill, possibly related to Permian or Permo-Triassic sedimentary rocks to the east in the Olive River area. The other packages consist of poorly defined, discontinuous, high velocity rocks believed to be related to those of the Bamaga Basin which have been mapped further north.During the period 1990-1993 Comalco Aluminium Limited reprocessed 2188 km of existing seismic data and acquired 2657 km of new seismic data over the offshore Carpentaria Basin. When combined with onshore seismic and the results of drilling previously undertaken by Comalco near Weipa on northwestern Cape York Peninsula, it was possible to define a significant and untested play in the Carpentaria Depression, the deepest part of the offshore Carpentaria Basin.The main play in the basin is the late Jurassic to early Cretaceous reservoir sandstones and source rocks, sealed by thick early Cretaceous mudstones. Possible pre-Jurassic source rocks are also present in discontinuous fault controlled half-grabens underlying the Carpentaria Basin. New detailed basin modelling suggests both the lower part of the Carpentaria Basin and any pre Jurassic section are mature within the depression and any source rocks present should have expelled oil.

Petroleum source rocks of Western Australia

2018 ◽  
Vol 58 (1) ◽  
pp. 282 ◽  
Author(s):  
K. Ameed R. Ghori
Keyword(s):  
Western Australia ◽  
Oil And Gas ◽  
Source Rocks ◽  
Lower Permian ◽  
Burial History ◽  
Canning Basin ◽  
Petroleum Systems ◽  
Northern Carnarvon Basin ◽  
Coal Measures ◽  
Carnarvon Basin

Petroleum geochemical analysis of samples from the Canning, Carnarvon, Officer and Perth basins identified several formations with source potential, the: • Triassic Locker Shale and Jurassic Dingo Claystone of the Northern Carnarvon Basin; • Permian Irwin River Coal Measures and Carynginia Formation, Triassic Kockatea Shale and Jurassic Cattamarra Coal Measures of the Perth Basin; • Ordovician Goldwyer and Bongabinni formations, Devonian Gogo Formation and Lower Carboniferous Laurel Formation of the Canning Basin; • Devonian Gneudna Formation of the Gascoyne Platform and the Lower Permian Wooramel and Byro groups of the Merlinleigh Sub-basin of the Southern Carnarvon Basin; and • Neoproterozoic Brown, Hussar, Kanpa and Steptoe formations of the Officer Basin. Burial history and geothermal basin modelling was undertaken using input parameters from geochemical analyses of rock samples, produced oil, organic petrology, apatite fission track analysis (AFTA), heat flows, subsurface temperatures and other exploration data compiled by the Geological Survey of Western Australia (GSWA). Of these basins, the Canning, Carnarvon, and Perth basins are currently producing oil and gas, whereas the Southern Carnarvon and Officer basins have no commercial petroleum discovery yet, but they do have source, reservoir, seal and petroleum shows indicating the presence of petroleum systems. The Carnarvon Basin contains the richest identified petroleum source rocks, followed by the Perth and Canning basins. Production in the Carnarvon Basin is predominantly gas and oil, the Perth Basin is gas-condensate and the Canning Basin is oil dominated, demonstrating the variations in source rock type and maturity across the state. GSWA is continuously adding new data to assess petroleum systems and prospectivity of these and other basins in Western Australia.

Oil migration makes the difference: regional distribution of carbonate cement δ13C in northern North Sea Tertiary sandstones

Clay Minerals ◽  
2000 ◽  
Vol 35 (1) ◽  
pp. 69-76 ◽  
Author(s):  
C. I. Macaulay ◽  
A. E. Fallick ◽  
R. S. Haszeldine ◽  
G. E. McAulay
Keyword(s):  
North Sea ◽  
Regional Distribution ◽  
Distribution Patterns ◽  
Source Rocks ◽  
Oil Migration ◽  
Bacterial Fermentation ◽  
Carbonate Cement ◽  
Carbonate Cements ◽  
Reservoir Sandstones ◽  
Northern North Sea

AbstractCarbonate cements in Tertiary reservoir sandstones from the northern North Sea have distinctive carbon isotopic compositions (δ13C). Oil migration up faults from deeper structures and biodegradation of oil pools are factors of particular importance in influencing the δ13C of carbonate cements in these sandstones. As a result, δ13C can be used as an exploration guide to locating the positions of vertical leakoff points from the Jurassic source rocks. The histogram distribution of δ13C in these carbonate cements is trimodal, with peaks at around −26, −3 and +12‰ (ranges −22 to −30, +2 to −10 and +8 to +18‰, respectively). Bacterial processes played major roles in determining this distribution, with oxidative biodegradation of oil resulting in carbonate cements with very negative compositions and bacterial fermentation resulting in the positive δ13C cements. δ13C distribution patterns may be used to differentiate Tertiary reservoir sandstones from Jurassic in the northern North Sea, and these regional carbonate cement δ13C datasets allow geologically useful inferences to be drawn from δ13C data from new sample locations.

USING 2D AND 3D BASIN MODELLING TO INVESTIGATE CONTROLS ON HYDROCARBON MIGRATION AND ACCUMULATION IN THE VULCAN SUB-BASIN, TIMOR SEA, NORTHWESTERN AUSTRALIA

2004 ◽  
Vol 44 (1) ◽  
pp. 93 ◽  
Author(s):  
T. Fujii ◽  
G.W. O’Brien ◽  
P. Tingate ◽  
G. Chen
Keyword(s):  
Late Jurassic ◽  
3D Modelling ◽  
Source Rocks ◽  
Lateral Migration ◽  
Burial History ◽  
Oil Migration ◽  
Early Migration ◽  
Late Tertiary ◽  
Timor Sea ◽  
2D And 3D

2D and 3D basin models have been constructed of the southern and central parts of the Vulcan Sub-basin region, in the Timor Sea. This work was carried out to better elucidate the petroleum migration and accumulation histories, and exploration potential, of the region.2D/3D modelling in the Swan Graben indicates that horizontal and downward oil expulsion from the source rocks of the Late Jurassic Lower Vulcan Formation into the Plover Formation sandstone was active from the Early Cretaceous to the present day. Oil migration from the Lower Vulcan Formation into the Late Cretaceous Puffin Formation sands in the Puffin field was simulated by lateral migration along the bottom of an Upper Vulcan Formation seal and by vertical migration above the seal edge. Modelling also indicates that Late Jurassic sequences over the Montara Terrace are thermally immature, and did not contribute to the hydrocarbon accumulations in the region. On the other hand, 3D modelling results indicate that Middle Jurassic Plover Formation in the Montara Terrace became thermally mature after the Pliocene and hence it could contribute both to the hydrocarbon accumulations and the overall hydrocarbon inventory in the area.In the southern Cartier Trough, the Lower Vulcan Formation is typically at a lower thermal maturity than that seen in the Swan Graben, due to a combination of a relatively recent (Pliocene) enhanced burial history and a thinner Lower Vulcan Formation. Here, horizontal and downward oil/gas expulsion from the Lower Vulcan Formation into the Plover Formation sandstone was active from the Late Tertiary to present day, which is significantly later than the expulsion in the Swan Graben. Oil migration from the Lower Vulcan Formation into the Jabiru structure via the Plover Formation carrier bed, was simulated in both 2D and 3D modelling. In particular, 3D modelling simulated oil migration into the Jabiru structure, not only from the southern Cartier Trough after the Miocene, but also early migration from the northern Swan Graben in the Early Cretaceous.In the central Cartier Trough, the areal extent of both generation and expulsion increased as a result of rapid subsidence from about 5 Ma to present day. This Pliocene loading has resulted in the rapid maturation of the Early to Middle and Late Jurassic source system, and expulsion of oil very recently.

Comprehensive basin-wide 3D petroleum systems modelling providing new insights into proven petroleum systems and remaining prospectivity in the Exmouth Sub-basin, Australia

2020 ◽  
Vol 60 (2) ◽  
pp. 753
Author(s):  
Oliver Schenk ◽  
Craig Dempsey ◽  
Robbie Benson ◽  
Michael Cheng ◽  
Sugandha Tewari ◽  
...  
Keyword(s):  
Early Cretaceous ◽  
Late Jurassic ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Long Distance ◽  
North West ◽  
Petroleum Systems ◽  
Northern Carnarvon Basin ◽  
Hydrocarbon Expulsion

The Exmouth Sub-basin is part of the Northern Carnarvon Basin, offshore north-west Australia, and has undergone a complex tectonic history. Hydrocarbon exploration resulted in the discovery of a variety of oil and gas accumulations; however, their distribution and charge history from different petroleum systems is still poorly understood due to limited knowledge of the deeper basin architecture. The basin-wide, long-offset, broadband 2017 Exmouth 3D multiclient seismic dataset allowed a seamless interpretation into this deeper section. This work revealed new insights on the tectono-stratigraphic evolution of the Exmouth Sub-basin. Mesozoic extension, that was restricted to the latest Triassic, was followed by a sag phase with homogeneous, shale-dominated deposition, resulting in source rock potential for the entire Jurassic section. These findings, together with potential field modelling, were integrated into this first basin-wide 3D petroleum system model to better constrain the thermal history and petroleum systems. The model improved our understanding of the complex charge history of hydrocarbon fields. It predicts that hydrocarbon expulsion from Late Jurassic source rocks continued into the Late Cretaceous, a period when the regional Early Cretaceous Muderong Formation was an efficient seal rock. This implies that, in addition to long-distance, sub-Muderong migration, vertical, short-distance migration may have contributed significant petroleum charge to the discovered accumulations in the southern Exmouth Sub-basin. The model also predicts additional prospective areas: fault-seal structures within Early Cretaceous intervals north of the Novara Arch, intra-formational Late Jurassic sandstones north of the current fields (with low biodegradation risk) and Triassic reservoirs along the basin margins and north of the Jurassic depocentre.

scholarly journals NEW GEOCHEMICAL INSIGHTS INTO CENOZOIC SOURCE ROCKS IN AZERBAIJAN: IMPLICATIONS FOR PETROLEUM SYSTEMS IN THE SOUTH CASPIAN REGION

2021 ◽  
Vol 44 (3) ◽  
pp. 349-384 ◽  
Author(s):  
V. Aghayeva ◽  
R. F. Sachsenhofer ◽  
C.G.C. van Baak ◽  
A. Bechtel ◽  
T. M. Hoyle ◽  
...  
Keyword(s):  
Source Rocks ◽  
Caspian Region ◽  
The South ◽  
Petroleum Systems

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.

Study on the Forming Conditions of Shale Gas in Coal Measure of Wuli Area, Qinghai Province, China

2013 ◽  
Vol 295-298 ◽  
pp. 2770-2773 ◽  
Author(s):  
Dai Yong Cao ◽  
Jing Li ◽  
Ying Chun Wei ◽  
Xiao Yu Zhang ◽  
Chong Jing Wang
Keyword(s):  
Shale Gas ◽  
Thermal Evolution ◽  
Organic Matter Content ◽  
Gas Production ◽  
Matter Content ◽  
Source Rocks ◽  
Coal Measure ◽  
Gas Generation ◽  
Qinghai Province ◽  
Coal Measures

Besides coal seam, the source rocks including dark mudstone, carbon mudstone and so on account for a large proportion in the coal measures. Based on the complex geothermal evolution history, the majority of coal measure organic matters with the peak of gas generation have a good potential of gas. Therefore, shale gas in coal measure is an important part of the shale gas resources. There are good conditions including the thickness of coal measures, high proportion of shale rocks, rich in organic matter content, high degree of thermal evolution, high content of brittle mineral and good conditions of the porosity and permeability for the generation of shale gas in Wuli area, the south of Qinghai province. Also the direct evidence of the gas production has been obtained from the borehole. The evaluation of shale gas in coal measure resources could broaden the understanding of the shale gas resources and promote the comprehensive development of the coal resources.

scholarly journals LA-ICP-MS U-Pb dating and geochemical characterization of oil inclusion-bearing calcite cements: Constraints on primary oil migration in lacustrine mudstone source rocks

2021 ◽  
Author(s):  
Ao Su ◽  
Honghan Chen ◽  
Yue-xing Feng ◽  
Jian-xin Zhao
Keyword(s):  
Fluid Inclusion ◽  
Inductively Coupled Plasma ◽  
Homogenization Temperature ◽  
Source Rocks ◽  
Oil Migration ◽  
Carbon And Oxygen Isotope ◽  
Fluorescence Characteristics ◽  
Calcite Veins ◽  
Migration Event

To date, few isotope age constraints on primary oil migration have been reported. Here we present U-Pb dating and characterization of two fracture-filling, oil inclusion-bearing calcite veins hosted in the Paleocene siliciclastic mudstone source rocks in Subei Basin, China. Deposition age of the mudstone formation was estimated to be ca. 60.2−58.0 Ma. The first vein consists of two major phases: a microcrystalline-granular (MG) calcite phase, and a blocky calcite phase, each showing distinctive petrographic features, rare earth element patterns, and carbon and oxygen isotope compositions. The early MG phase resulted from local mobilization of host carbonates, likely associated with disequilibrium compaction over-pressuring or tectonic extension, whereas the late-filling blocky calcite phase was derived from overpressured oil-bearing fluids with enhanced fluid-rock interactions. Vein texture and fluorescence characteristics reveal at least two oil expulsion events, the former represented by multiple bitumen veinlets postdating the MG calcite generation, and the latter marked by blue-fluorescing primary oil inclusions synchronous with the blocky calcite cementation. The MG calcite yields a laser ablation−inductively coupled plasma−mass spectrometry U-Pb age of 55.6 ± 1.4 Ma, constraining the earliest timing of the early oil migration event. The blocky calcite gives a younger U-Pb age of 47.8 ± 2.3 Ma, analytically indistinguishable from the U-Pb age of 46.5 ± 1.7 Ma yielded by the second calcite vein. These two ages define the time of the late oil migration event, agreeing well with the age estimate of 49.7−45.2 Ma inferred from fluid-inclusion homogenization temperature and published burial models. Thermodynamic modeling shows that the oil inclusions were trapped at ∼27.0−40.9 MPa, exceeding corresponding hydrostatic pressures (23.1−26.7 MPa), confirming mild-moderate overpressure created by oil generation-expulsion. This integrated study combining carbonate U-Pb dating and fluid-inclusion characterization provides a new approach for reconstructing pressure-temperature-composition-time points in petroleum systems.

Hydrocarbon fluid inclusions in the Argo salt, offshore Canadian Atlantic margin

2013 ◽  
Vol 50 (6) ◽  
pp. 607-635 ◽  
Author(s):  
Yawooz A. Kettanah
Keyword(s):  
Fluid Inclusions ◽  
Fluorescent Microscopy ◽  
Freezing Temperature ◽  
Homogenization Temperature ◽  
Source Rocks ◽  
Late Triassic ◽  
Peritectic Temperature ◽  
Petroleum Systems ◽  
Initial Melting ◽  
Atlantic Margin

Fluid inclusions hosted in rock salt from the Triassic Argo Formation in the Canadian Atlantic continental margin were studied to investigate the nature and origin of petroleum fluids in them. Inclusions were studied in two wells: Glooscap-C63 and Weymouth-A45. The pillow-shaped salt body intersected by the Glooscap-C63 well is autochthonous, and the salt is transparent and colorless compared with that in the allochthonous, canopy–diaper-shaped body cut by the Weymouth-A45 well which is translucent and buff-colored. Aqueous (AFI), petroleum (PFI), and heterogeneously trapped, mixed petroleum – aqueous (MFI) fluid inclusions were identified using transmitted and fluorescent microscopy, and representative samples were analyzed microthermometrically. Petroleum-bearing fluid inclusions (PFI and MFI) are more common and contain more concentrated petroleum phases in the allochthonous salts of Weymouth-A45 well. Based on microthermometric studies, the AFI and MFI in Glooscap-C63 salt mostly belong to NaCl–H2O and NaCl–H2O–petroleum systems, respectively; in contrast, those of Weymouth-A45 belong to NaCl–MgCl2–H2O and (or) NaCl–CaCl2–H2O and NaCl–MgCl2–H2O–petroleum and (or) NaCl–CaCl2–H2O–petroleum systems, respectively. Each of the AFI, PFI, and MFI types consists of different phases. The medians of Tf (freezing temperature), Tim (initial melting temperature), Te (Eutectic temperature), Tm (final melting (peritectic) temperature), and Th (homogenization temperature) in the AFI and MFI in the salts of Glooscap-C63 well are (−82, −75 °C), (−39, −38 °C), (−25, −24 °C), (−1.8, −3 °C), and (291, 287 °C), respectively. The corresponding medians for the Weymouth-A45 well are (−71, −78 °C), (−52, −52 °C), (−37, −38 °C), (−2.7, −3 °C), and (122, 20 °C), respectively. The median Th of PFI in Glooscap-C63 and Weymouth-A45 salts are 79 and 23 °C, respectively. The most probable source rocks for the petroleum are the shales of the Late Triassic – Early Jurassic Eurydice Formation which is widely distributed at depth underlying the Argo salt.

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