New insights into the petroleum prospectivity of the Browse Basin: the results of a multi-disciplinary study

2016 ◽  
Vol 56 (1) ◽  
pp. 483 ◽  
Author(s):  
Nadege Rollet ◽  
Emmanuelle Grosjean ◽  
Dianne Edwards ◽  
Tehani Palu ◽  
Steve Abbott ◽  
...  
Keyword(s):  
Source Rock ◽  
Spatial Relationship ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
North West ◽  
Petroleum Systems ◽  
Systems Model ◽  
Hydrocarbon Expulsion

The Browse Basin hosts large gas accumulations, some of which are being developed for conventional liquefied natural gas (LNG). Extensive appraisal drilling has been focused in the central Caswell Sub-basin at Ichthys and Prelude, and along the extended Brecknock-Scott Reef Trend; whereas elsewhere the basin remains underexplored. To provide a better understanding of regional hydrocarbon prospectivity, the sequence stratigraphy of the Cretaceous succession and structural framework were analysed to determine the spatial relationship of reservoir and seal pairs, and those areas of enhanced source rock development. The sequence stratigraphic interpretation is based upon a common North West Shelf stratigraphic framework that has been developed in conjunction with industry, and aligned with the international time scale. Sixty key wells and 2D and 3D seismic data have been interpreted to produce palaeogeographic maps and depositional models for the Cretaceous succession. Geochemical analyses have characterised the molecular and stable isotopic signatures of fluids and correlated them with potential source rocks. The resultant petroleum systems model provides a more detailed understanding of source rock maturity, organic richness and hydrocarbon-generation potential in the basin. The model reveals that many accumulations have a complex charge history, with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, including the Lower–Middle Jurassic J10–J20 supersequences (Plover Formation), Upper Jurassic–Lowermost Cretaceous J30–K10 supersequences (Vulcan Formation), and Lower Cretaceous K20–K30 supersequences (Echuca Shoals Formation). Burial history and hydrocarbon expulsion models, applied to these Jurassic and Cretaceous supersequences, suggest that numerous petroleum systems are effective within the basin. For example, hydrocarbons are interpreted to have been generated from several source pods within the southern Caswell Sub-basin with migration continuing onto the Yampi Shelf, an area of renewed exploration interest.

Material Balance Method Combined with Hydrocarbon Generation Kinetics to Calculate the Efficiency of Hydrocarbon Expulsion

2014 ◽  
Vol 977 ◽  
pp. 73-77
Author(s):  
Ai Hua Huang ◽  
Min Wang ◽  
Shan Si Tian ◽  
Hai Tao Xue ◽  
Zhi Wei Wang ◽  
...  
Keyword(s):  
Material Balance ◽  
Order Reaction ◽  
Balance Method ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
First Order ◽  
Geochemical Parameters ◽  
Material Balance Method ◽  
Hydrocarbon Expulsion

In order to calculate the efficiency of hydrocarbon expulsion by material balance method, we analyzed and corrected the geochemical parameters of five source rock samples. The hydrocarbon generation kinetic parameters of these samples were calibrated by the model of limited parallel first order reaction, and then these were extrapolated with the burial history and thermal history, then we got the hydrocarbon-generating section. Combined with the corrected geochemical parameters calculate the generating hydrocarbon amounts and expulsive hydrocarbon amounts. The result shows that: expulsion efficiency of hydrocarbon source rocks in this research were mainly between 59.1% -91.8%. It is determined by maturity (Ro), type of organic matter and pyrolysis parameters S1、S2.

Petroleum systems of the Bass Basin: a 3D modelling perspective

2010 ◽  
Vol 50 (1) ◽  
pp. 511 ◽  
Author(s):  
Natt Arian ◽  
Peter Tingate ◽  
Richard Hillis ◽  
Geoff O'Brien
Keyword(s):  
Middle Eastern ◽  
Source Rocks ◽  
Petroleum Systems ◽  
Systems Model ◽  
Basin Scale ◽  
Exploration Risk ◽  
New Locations ◽  
Petroleum Generation ◽  
And Migration ◽  
Hydrocarbon Expulsion

Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin; however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal. The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited; however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations. The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources; however, Miocene reactivation is a major exploration risk in this area.

HYDROCARBON GENERATION AND EXPULSION FROM EARLY CRETACEOUS SOURCE ROCKS IN THE BROWSE BASIN, NORTH WEST SHELF, AUSTRALIA: A SMALL ANGLE NEUTRON SCATTERING STUDY

2004 ◽  
Vol 44 (1) ◽  
pp. 151 ◽  
Author(s):  
A.P. Radlinski ◽  
J.M. Kennard ◽  
D.S. Edwards ◽  
A.L. Hinde ◽  
R. Davenport
Keyword(s):  
Neutron Scattering ◽  
Pore Size ◽  
Source Rock ◽  
Early Cretaceous ◽  
Small Angle ◽  
Small Angle Neutron Scattering ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
North West

Small Angle Neutron Scattering (SANS) analyses were carried out on 165 potential source rocks of Late Jurassic–Early Cretaceous age from nine wells in the Browse Basin (Adele–1, Argus–1, Brecknock South–1, Brewster–1A, Carbine–1, Crux–1, Dinichthys–1, Gorgonichthys–1 and Titanichthys–1). Samples from Brewster–1A and Dinichthys–1 were also analysed using the Ultra Small Angle Neutron Scattering (USANS) technique.The SANS/USANS data detect the presence of generated bitumen and mobile hydrocarbons in pores and are pore-size specific. As the pore-size range in mudstones extends from about 0.001–30 μm, the presence of bitumen in the small pores detected by SANS indicates the depth of onset of hydrocarbon generation, whereas the presence of bitumen and mobile hydrocarbons in the largest pores detected by USANS indicates a significant saturation and the onset of expulsion.Although geochemical data imply the existence of a potential gas and oil source rock in the Lower Cretaceous section (Echuca Shoals and Jamieson Formations), the SANS/USANS data indicate significant generation but little or no expulsion. This source limitation may explain poor exploration success for liquid hydrocarbons in the area. The SANS/USANS data provide evidence of intra- and inter-formational hydrocarbon migration or kerogen kinetics barriers. There is no evidence of an oil charge to the Berriasian Brewster Sandstone from the Echuca Shoals Formation, although some gas charge in Brewster–1A is possible. This novel microstructural technique can be used to independently calibrate and refine source rock generation/expulsion scenarios derived from geochemistry modelling.

scholarly journals Reconstruction of burial history, temperature, source rock maturity and hydrocarbon generation in the northwestern Dutch offshore

2012 ◽  
Vol 91 (4) ◽  
pp. 535-554 ◽  
Author(s):  
R. Abdul Fattah ◽  
J.M. Verweij ◽  
N. Witmans ◽  
J.H. ten Veen
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Northwestern Part ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Coal Seams ◽  
Gas Generation ◽  
Offshore Area ◽  
The North ◽  
Late Generation

Abstract3D basin modelling is used to investigate the history of maturation and hydrocarbon generation on the main platforms in the northwestern part of the offshore area of the Netherlands. The study area covers the Cleaverbank and Elbow Spit Platforms. Recently compiled maps and data are used to build the input geological model. An updated and refined palaeo water depth curve and newly refined sediment water interface temperatures (SWIT) are used in the simulation. Basal heat flow is calculated using tectonic models. Two main source rock intervals are defined in the model, Westphalian coal seams and pre-Westphalian shales, which include Namurian and Dinantian successions. The modelling shows that the pre-Westphalian source rocks entered the hydrocarbon generation window in the Late Carboniferous. In the southern and central parts of the study area, the Namurian started producing gas in the Permian. In the north, the Dinantian source rocks appear to be immature. Lower Westphalian sediments started generating gas during the Upper Triassic. Gas generation from Westphalian coal seams increased during the Paleogene and continues in present-day. This late generation of gas from Westphalian coal seams is a likely source for gas accumulations in the area.Westphalian coals might have produced early nitrogen prior to or during the main gas generation occurrence in the Paleogene. Namurian shales may be a source of late nitrogen after reaching maximum gas generating phase in the Triassic. Temperatures reached during the Mid Jurassic were sufficiently high to allow the release of non-organic nitrogen from Namurian shales.

scholarly journals Are Carboniferous coals from the Danish North Sea oil-prone?

2007 ◽  
Vol 13 ◽  
pp. 13-16 ◽  
Author(s):  
Henrik I. Petersen ◽  
Hans P. Nytoft
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Lower Carboniferous ◽  
North West ◽  
The North ◽  
Single Well ◽  
The North Sea ◽  
Clay Formation

The Central Graben in the North Sea is a mature petroleum province with Upper Jurassic – lowermost Cretaceous marine shale of the Kimmeridge Clay Formation and equivalents as the principal source rock, and Upper Cretaceous chalk as the main reservoirs. However, increasing oil prices and developments in drilling technologies have made deeper plays depending on older source rocks increasingly attractive. In recent years exploration activities have therefore also been directed towards deeper clastic plays where Palaeozoic deposits may act as petroleum source rocks. Carboniferous coaly sections are the most obvious source rock candidates. The gas fields of the major gas province in the southern North Sea and North-West Europe are sourced from the thick Upper Carboniferous Coal Measures, which contain hundreds of coal seams (Drozdzewski 1993; Lokhorst 1998; Gautier 2003). North of the gas province Upper Carboni-ferous coal-bearing strata occur onshore in northern England and in Scotland, but offshore in the North Sea area they have been removed by erosion. However, Lower Carboniferous strata are present offshore and have been drilled in the Witch Ground Graben and in the north-eastern part of the Forth Approaches Basin (Fig. 1A), where most of the Lower Carbon iferous sediments are assigned to the sandstone/shale-dominated Tayport For mation and to the coal-bearing Firth Coal Formation (Bruce & Stemmerik 2003). Highly oil-prone Lower Carboniferous lacustrine oil shales occur onshore in the Midland Valley, Scotland, but they have only been drilled by a single well off shore and seem not to be regionally distributed (Parnell 1988). In the southern part of the Norwegian and UK Central Graben and in the Danish Central Graben a total of only nine wells have encountered Lower Carboniferous strata, and while they may have a widespread occurrence (Fig. 1B; Bruce & Stemmerik 2003) their distribution is poorly constrained in this area. The nearly 6000 m deep Svane-1/1A well (Fig. 1B) in the Tail End Graben encountered gas and condensate at depths of 5400–5900 m, which based on carbon isotope values may have a Carboniferous source (Ohm et al. 2006). In the light of this the source rock potential of the Lower Carboniferous coals in the Gert-2 well (Fig. 1C) has recently been assessed (Petersen & Nytoft 2007).

Dynamics of Hydrocarbon Expulsion from Shale Source Rocks

2005 ◽  
Vol 23 (5) ◽  
pp. 333-355 ◽  
Author(s):  
Xiongqi Pang ◽  
Zhenxue Jiang ◽  
Shengjie Zuo ◽  
Ian Lerche
Keyword(s):  
Source Rock ◽  
Driving Forces ◽  
Water Solution ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Second Stage ◽  
The Third ◽  
Third Stage ◽  
Two Factors ◽  
Hydrocarbon Expulsion

Expulsion of hydrocarbons from a shale source rock can be divided in four stages. In the first stage, only a small amount of hydrocarbons can be expelled in water solution and by diffusion. Compaction and hydrocarbon concentration gradient are the major driving forces, whereas their corresponding hydrocarbon expulsion amounts make up 30% and 70% to the total, respectively. In the second stage, in addition to transport by water solution and by diffusion, source rocks expel a large quantity of gas in free phase. In the third stage, the most important feature is that source rocks expel oil as a separate phase and gas in oil solution. Hydrocarbon expulsion by diffusion through the source rock organic network, dehydration of clay minerals, and thermal expansion of fluids and rocks are the three major driving forces in the second and the third stages, whereas the corresponding hydrocarbon expulsion accounts for 40–60%, 10–20%, and 5–10%, respectively, of the total amount expelled. In the fourth stage, source rocks mainly expel dry gas as a free phase. Volume expansion of kerogen products and capillary force are the two major driving forces for hydrocarbon expulsion. The expulsion accounts for 60% and 30% to the total gas expulsion of this stage, respectively, for each driving force. Hydrocarbon expulsion, including the hydrocarbon expulsion threshold (HET), the relative phases and the dynamics, are controlled by two factors: the hydrocarbon generation amount, and the ability of source rocks to retain hydrocarbons. Source rocks cross the HET and begin to expel a large quantity of hydrocarbons when the generated hydrocarbons have met all of the needs for hydrocarbon retention. HET is divides the processes of hydrocarbon expulsion into the various four stages.

Petroleum systems analysis of the northern Houtman Sub-basin

2017 ◽  
Vol 57 (2) ◽  
pp. 755 ◽  
Author(s):  
Lisa Hall ◽  
Emmanuelle Grosjean ◽  
Irina Borissova ◽  
Chris Southby ◽  
Ryan Owens ◽  
...  
Keyword(s):  
Systems Analysis ◽  
Source Rocks ◽  
Rock Properties ◽  
Hydrocarbon Generation ◽  
Petroleum Systems ◽  
Systems Model ◽  
Potential Source ◽  
Lithospheric Extension ◽  
Half Graben ◽  
Potential Field Modelling

Interpretation of newly acquired seismic data in the northern Houtman Sub-basin (Perth Basin) suggests the region contains potential source rocks similar to those in the producing Abrolhos Sub-basin. The regionally extensive late Permian–Early Triassic Kockatea Shale has the potential to contain the oil-prone Hovea Member source interval. Large Permian syn-rift half-graben, up to 10 km thick, are likely to contain a range of gas-prone source rocks. Further potential source rocks may be found in the Jurassic–Early Cretaceous succession, including the Cattamarra Coal Measures, Cadda shales and mixed sources within the Yarragadee Formation. This study investigated the possible maturity and charge history of these different source rocks. A regional pseudo-3D petroleum systems model was constructed using new seismic interpretations. Heat flow was modelled using crustal structure and possible basement composition determined from potential field modelling, and subsidence analysis was used to investigate lithospheric extension through time. The model was calibrated using temperature and maturity data from nine wells in the Houtman and Abrolhos sub-basins. Source rock properties are assigned based on an extensive review of total organic carbon, Rock Eval and kinetic data for the offshore northern Perth Basin. Petroleum systems analysis results show that Permian, Triassic and Early Jurassic source rocks may have generated large cumulative volumes of hydrocarbons across the northern Houtman Sub-basin, whereas the Middle Jurassic–Cretaceous sources remain largely immature. However, the timing of hydrocarbon generation and expulsion with respect to trap formation and structural reactivation is critical for the successful development and preservation of hydrocarbon accumulations.

Clay diagenesis in the Kimmeridge Clay Formation, onshore UK, and its relation to organic maturation

1987 ◽  
Vol 51 (362) ◽  
pp. 535-551 ◽  
Author(s):  
Iain C. Scotchman
Keyword(s):  
Source Rock ◽  
Fine Fraction ◽  
Upper Jurassic ◽  
Hydrocarbon Generation ◽  
The North ◽  
And Migration ◽  
Oil Source ◽  
Hydrocarbon Expulsion ◽  
The Uk ◽  
Clay Formation

AbstractConversion of randomly ordered illite-smectite to ordered illite-smectite in the Upper Jurassic Kimmeridge Clay Formation from the North Sea has been recorded in the literature as occurring within the ‘oil window’ and has been suggested as an indicator of oil source rock maturity. Studies of authigenic clay minerals in the fine fraction (>0.5 µm) of the Kimmeridge Clay Formation mudstones from fourteen locations along the UK onshore outcrop between Dorset and North Yorkshire show that they comprise mainly ordered illite-smectites. The onshore Kimmeridge Clay section is organically immature, suggesting that the illite-smectite ordering reaction cannot be extrapolated between basins as an inorganic indicator of ‘oil window’ levels of maturity. These results also have important implications in source rock hydrocarbon expulsion and migration models which involve shale dewatering as a flushing agent. However, dewatering of shales may aid migration as it could cause fracturing of the shale bands separating the organic-rich layers within the source rock, prior to hydrocarbon generation.

scholarly journals Oil And Gas Generation History Based On Burial History Reconstruction And Thermal Maturity Modeling Of Petroleum Systems In Northern Iraq

2020 ◽  
Vol 10 (4) ◽  
pp. 95-120
Author(s):  
Rzger Abdulkarim Abdula
Keyword(s):  
Source Rock ◽  
Late Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Burial History ◽  
Gas Generation ◽  
Northern Iraq ◽  
Oil Generation

Burial history, thermal maturity, and timing of hydrocarbon generation were modeled for five key source-rock horizons at five locations in Northern Iraq. Constructed burial-history locations from east to west in the region are: Taq Taq-1; Qara Chugh-2; Zab-1; Guwair-2; and Shaikhan-2 wells. Generally, the thermal maturity status of the burial history sites based on increasing thermal maturity is Shaikhan-2 < Zab-1 < Guwair-2 < Qara Chugh-2 < Taq Taq-1. In well Qara Chugh-2, oil generation from Type-IIS kerogen in Geli Khana Formation started in the Late Cretaceous. Gas generation occurred at Qara Chugh-2 from Geli Khana Formation in the Late Miocene. The Kurra Chine Formation entered oil generation window at Guwair-2 and Shaikhan-2 at 64 Ma and 46 Ma, respectively. At Zab-1, the Baluti Formation started to generate gas at 120 Ma. The Butmah /Sarki reached peak oil generation at 45 Ma at Taq Taq-1. The main source rock in the area, Sargelu Formation started to generate oil at 47, 51, 33, 28, and 28 Ma at Taq Taq-1, Guwair-2, Shaikhan-2, Qara Chugh-2, and Zab-1, respectively. The results of the models demonstrated that peak petroleum generation from the Jurassic oil- and gas-prone source rocks in the most profound parts of the studied area occurred from Late Cretaceous to Middle Oligocene. At all localities, the Sargelu Formation is still within the oil window apart from Taq Taq-1 and Qara Chugh-2 where it is in the oil cracking and gas generation phase.

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.

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