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.

THERMAL HISTORY MODELLING AND TRANSIENT HEAT PULSES: NEW INSIGHTS INTO HYDROCARBON EXPULSION AND 'HOT FLUSHES' IN THE VULCAN SUB-BASIN, TIMOR SEA

1999 ◽  
Vol 39 (1) ◽  
pp. 177 ◽  
Author(s):  
J.M. Kennard ◽  
I. Deighton ◽  
D.S. Edwards ◽  
J.B. Colwell ◽  
G.W. O'Brien ◽  
...  
Keyword(s):  
Thermal History ◽  
Burial History ◽  
History Analysis ◽  
Late Tertiary ◽  
History Of ◽  
Timor Sea ◽  
Heat Pulses ◽  
Nearby Source ◽  
Hydrocarbon Expulsion ◽  
Thermal Pulses

Thermal history data from wells in the Vulcan Sub- basin and adjacent platforms show clear evidence that many reservoir sections have experienced relatively shortlived, high- temperature flushes during the Late Tertiary. These transient heat pulses are related to slow migration of hot fluids and hydrocarbons from adjacent depocentres, or rapid flow of deep-seated brines during Late Miocene- Early Pliocene tectonic reactivation. The hot fluids have been focussed into structured reservoir sections via high- permeability pathways and reactivated faults. As a consequence, most exploration wells are not truly representative of the thermal regime of nearby source kitchens.In order to constrain the regional thermal and expulsion history of the region, and to address the issue of thermal pulses, burial history analysis of 44 wells and 18 depocentre sites was carried out. This analysis utilises a simplified transient heat pulse model developed as part of the WinBury™ burial and thermal geohistory modelling software. The transient and steady-state thermal history models are constrained by reflectance and fluorescence maturity data, together with apatite fission track analysis and fluid inclusion palaeo-temperature data.

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.

EXPLORATION IN THE NORTHERN BONAPARTE BASIN, TIMOR SEA - WA-199-P

1990 ◽  
Vol 30 (1) ◽  
pp. 7
Author(s):  
Mike Whibley ◽  
Ted Jacobson
Keyword(s):  
Late Jurassic ◽  
Fault Reactivation ◽  
Coarse Grained ◽  
3D Seismic ◽  
Submarine Fan ◽  
Oil Migration ◽  
Island Group ◽  
Main Period ◽  
Timor Sea ◽  
Exploration Phase

Permit WA-199-P, located in the Northern Bonaparte Basin, has undergone an intensive exploration phase from its award on 22 October 1985, which has resulted in the acquisition of 6250 km of 2D seismic and 1558 km of 3D seismic together with the drilling of seven exploration wells. Significant oil shows were recorded in six of these wells.The major play type investigated to date within the permit consists of Jurassic tilted horst and fault blocks. Potential reservoirs comprising medium to coarse grained sandstones of the Jurassic Plover Formation and, to a lesser extent, the Late Jurassic to Early Cretaceous Flamingo Group, are sealed by massive claystones of the Cretaceous Bathurst Island Group. Numerous oil shows have been encountered by drilling within these two reservoirs; however, drilling results from the Avocet-Eider structure indicate that Late Miocene-Recent fault reactivation often breaches the lateral seal of the fault- dependent structures causing leakage of hydrocarbons up the fault.Source extract-oil correlations and maturation studies indicate that the most likely oil sources comprise thermally mature marine claystones of the Flamingo Group and Plover Formation, developed within the Sahul Syncline to the east of WA-199-P. The main period of oil migration was probably Miocene or younger. A number of play types remain untested. These consist of Permian, Intra-Triassic and top Cretaceous fault blocks, as well as fault-independent closures, downdip fault closures and stratigraphic wedge outs of Maastrichtian sand reservoirs, and submarine fan sands developed within the basal Flamingo Group.

Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models

2019 ◽  
Vol 56 (4) ◽  
pp. 365-396
Author(s):  
Debra Higley ◽  
Catherine Enomoto
Keyword(s):  
New York ◽  
Vitrinite Reflectance ◽  
Structural Complexity ◽  
Appalachian Basin ◽  
Source Rocks ◽  
Burial History ◽  
Gas Generation ◽  
Deep Basin ◽  
Utica Shale ◽  
Wet Gas

Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

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.

Estimation Update and Feedback Procedures

2008 ◽  
Author(s):  
P.J. Lee
Keyword(s):  
Water Saturation ◽  
Geophysical Data ◽  
Source Rocks ◽  
Geochemical Data ◽  
Burial History ◽  
Data Types ◽  
Petroleum Resource ◽  
History Of ◽  
Seismic Sections ◽  
Well Data

A basin or subsurface study, which is the first step in petroleum resource evaluation, requires the following types of data: • Reservoir data—pool area, net pay, porosity, water saturation, oil or gas formation volume factor, in-place volume, recoverable oil volume or marketable gas volume, temperature, pressure, density, recovery factors, gas composition, discovery date, and other parameters (refer to Lee et al., 1999, Section 3.1.2). • Well data—surface and bottom well locations; spud and completion dates; well elevation; history of status; formation drill and true depths; lithology; drill stem tests; core, gas, and fluid analyses; and mechanical logs. • Geochemical data—types of source rocks, burial history, and maturation history. • Geophysical data—prospect maps and seismic sections. Well data are essential when we construct structural contour, isopach, lithofacies, porosity, and other types of maps. Geophysical data assist us when we compile number-of-prospect distributions and they provide information for risk analysis.

HYDROCARBON HABITAT OF THE SURAT/BOWEN BASIN

1982 ◽  
Vol 22 (1) ◽  
pp. 213 ◽  
Author(s):  
B. M. Thomas ◽  
D. G. Osborne ◽  
A. J. Wright
Keyword(s):  
Oil And Gas ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Lateral Migration ◽  
Early Maturity ◽  
Oil And Gas Fields ◽  
Basement Rocks ◽  
Origin Of Oil ◽  
Gas Fields ◽  
Geochemical Studies

Ever since the early discoveries at Cabawin (1960) and Moonie (1961), the origin of oil and gas in the Surat/Bowen Basin has been a subject of speculation. Hydrocarbons have been found in reservoirs ranging in age from Permian to Early Jurassic; even fractured pre-Permian 'basement' rocks have occasionally recorded shows.Recent geochemical studies have identified rich source rocks within the Jurassic, Triassic and Permian sequences. The Middle Jurassic Walloon Coal Measures are thermally immature throughout the Surat Basin and are unlikely to have generated significant amounts of hydrocarbons. Lower Jurassic Evergreen Formation source rocks have reached 'nominal early maturity' (VR = 0.6) in parts of the basin. The Middle Triassic Moolayember Formation lies within the oil generation zone in the northern Taroom Trough. However, no oil has yet been confidently correlated with either a Jurassic or a Triassic source. On geochemical and geological grounds it is likely that most, if not all, of the hydrocarbons discovered to date were generated from Permian source rocks.The probability of finding gas as well as oil in Permian, Triassic or Jurassic reservoirs increases from south to north, in accord with organic maturity trends in the Permian of the Taroom Trough. On the narrow thrust-bounded eastern flank, vertical migration has occurred, resulting in oilfields at Moonie and Bennett. In contrast, extensive lateral migration of hydrocarbons across the gentle western flank of the basin is indicated by numerous small oil and gas fields on the Roma Shelf and Wunger Ridge.

THE OTWAY BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 417 ◽  
Author(s):  
S. Laing ◽  
C.N. Dee ◽  
P.W. Best
Keyword(s):  
Lacustrine Sediments ◽  
South Australia ◽  
Commercial Production ◽  
Source Rocks ◽  
Mature Stage ◽  
Tectonic Events ◽  
Late Tertiary ◽  
Marine Carbonates ◽  
Initial Deposition ◽  
Commercial Oil

The Otway Basin covers an area of some 150 000 km2 both onshore and offshore southwestern Victoria and southeastern South Australia. Exploration within the basin is at a moderately mature stage by Australian standards (though immature by world standards), with a well density of one per 1500 km2, including offshore areas.Formation of the Otway Basin commenced in the late Jurassic with the initiation of rifting between Australia and Antarctica. As rifting continued, a number of depositional cycles occurred. Initial deposition comprised fluvio- lacustrine sediments, followed by marine transgressions and associated regressive deltaic cycles. As subsidence continued into the Late Tertiary, a series of marine carbonates and marls were deposited. The Otway Basin is structurally complex as a result of the superposition of a number of tectonic events which occurredboth during and after the development of the basin.The Otway Basin is a proven gas province, with commercial production at Caroline 1 (carbon dioxide) and North Paaratte Field (methane). Although no commercial oil production has yet been established in the basin, oil has been recovered at Port Campbell 4, Lindon 1 and Windermere 1. The presence of excellent reservoir units within the basin, mature source rocks and adequate seals, together with a number of untested play types and favourable economics, augurs well for the prospectivity of the Otway Basin.

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