Integrated petroleum systems analysis to understand the source of fluids in the Browse Basin, Australia

The Browse Basin is located offshore on Australia’s North West Shelf and is a proven hydrocarbon province, hosting gas with associated condensate in an area where oil reserves are typically small. The assessment of a basin’s oil potential traditionally focuses on the presence or absence of oil-prone source rocks. However, light oil can be found in basins where source rocks are gas-prone and the primary hydrocarbon type is gas-condensate. Oil rims form whenever such fluids migrate into reservoirs at pressures less than their dew point (saturation) pressure. By combining petroleum systems analysis with geochemical studies of source rocks and fluids (gases and liquids), four Mesozoic petroleum systems have been identified in the basin. This study applies petroleum systems analysis to understand the source of fluids and their phase behaviour in the Browse Basin. Source rock richness, thickness and quality are mapped from well control. Petroleum systems modelling that integrates source rock property maps, basin-specific kinetics, 1D burial history models and regional 3D surfaces, provides new insights into source rock maturity, generation and expelled fluid composition. The principal source rocks are Early–Middle Jurassic fluvio-deltaic coaly shales and shales within the J10–J20 supersequences (Plover Formation), Middle–Late Jurassic to Early Cretaceous sub-oxic marine shales within the J30–K10 supersequences (Vulcan and Montara formations) and K20–K30 supersequences (Echuca Shoals Formation). These source rocks contain significant contributions of terrestrial organic matter, and within the Caswell Sub-basin, have reached sufficient maturities to have transformed most of the kerogen into hydrocarbons, with the majority of expulsion occurring from the Late Cretaceous until present.

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A quantitative approach to regional screening of petroleum systems, Westralian Superbasin

The APPEA Journal ◽

10.1071/aj14036 ◽

2015 ◽

Vol 55 (2) ◽

pp. 401

Author(s):

Christopher Paschke ◽

Rob K. Sawyer ◽

Catherine Belgarde ◽

Chris Yarborough ◽

Christina Huenink

Keyword(s):

Source Rock ◽

Systems Analysis ◽

Regional Scale ◽

Source Rocks ◽

Regional Study ◽

Seismic Line ◽

Petroleum Systems ◽

Reflection Seismic ◽

Stratigraphic Position

The greater Westralian Superbasin comprises multiple petroleum systems ranging in age from the Early Paleozoic to the Paleogene (Bradshaw et al, 1994). A subset of these systems is typified by marine incursions with a deposition of liquids-prone source rocks. Variability in Westralian sediment fill and source rock stratigraphic position can be demonstrated on a continuous mega-regional 2D deep reflection seismic line that extends from Carnarvon through Browse and into the Bonaparte Basin. Beginning in 2013, BHP Billiton initiated a comprehensive regional study of the Westralian margin to better risk existing and new play fairways. From this work, a hydrocarbon systems analysis from the Dampier Sub-basin and its application for exploration as a regional analogue is described. From a compilation of both open-file and proprietary data, a subset of Dampier well penetrations was chosen, based on the quality of available source rock data. 1D models were constructed and thermally calibrated to BHP Billiton’s recent re-interpretation of the sub-regional crustal architecture. The ultimate expelled petroleum (UEP) was calculated at each well and then extrapolated regionally to determine the total basin hydrocarbon potential. Maturity of the source rock is described using the state of thermal stress (STS) parameter (Pepper and Corvi, 1995). Compared with more data- and labour-intensive 3D basin modelling, integration of 1D basin models, UEP and STS parameters allow for a rapid quantitative and regional-scale basin analysis. Using this workflow in data-constrained basins like the Dampier Sub-basin serves as an important analogue for assessing and risking petroleum systems in both of the established and frontier portions of the Australian margin.

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

The APPEA Journal ◽

10.1071/aj15034 ◽

2016 ◽

Vol 56 (1) ◽

pp. 483 ◽

Cited By ~ 4

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.

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EVIDENCE FOR A NEW OIL FAMILY IN THE NANCAR TROUGH AREA, TIMOR SEA

The APPEA Journal ◽

10.1071/aj01021 ◽

2002 ◽

Vol 42 (1) ◽

pp. 387 ◽

Cited By ~ 3

Author(s):

S.C. George ◽

H. Volk ◽

T.E. Ruble ◽

M.P. Brincat

Keyword(s):

Organic Matter ◽

Fluid Inclusion ◽

Source Rock ◽

Bacterial Activity ◽

Source Rocks ◽

Drilling Mud ◽

Terrestrial Organic Matter ◽

High Contribution ◽

Timor Sea ◽

Oil Source

Geochemical evidence is presented for a previously unrecognised oil generative source rock in the Nancar Trough area. This source rock supplements the middle to late Jurassic source rocks, which have previously been shown to have generated most of the oils in the northern Bonaparte Basin and the Vulcan Sub-basin. Fluids with a strong contribution from this new source rock, defined here as the Nancar oil family, have an unusually high abundance of mid-chain substituted monomethylalkanes. In comparison, oils from the Vulcan Sub-basin contain mostly terminally substituted monomethylalkanes and the overall abundance is much lower. Oils from the Laminaria High and some from the northern Vulcan Sub-Basin show intermediate characteristics and may be co-sourced. Evidence from the analysis of fluid inclusion oils was important in establishing the presence of the new oil family because interference from drilling mud contaminants could be excluded. The detailed geochemistry of Ludmilla–1 fluid inclusion oil suggests the source rock for the Nancar oil family was deposited in a marine environment under sub-oxic conditions with limited sulphur content, a low contribution of terrestrial organic matter and a high contribution of organic matter from bacterial activity. Since monomethylalkanes are typical biomarkers of cyanobacteria, the source rock that gave rise to the new oil family may be rich in cyanobacterial organic matter. Further studies on sediment extracts are needed to establish an explicit oil-source rock correlation and to identify the stratigraphic location/palaeo-environment of the source rock. Such information will be valuable in determining the prospectivity of the large and relatively unexplored province draining the Nancar Trough kitchen.

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Cooper Basin source rock atlas

The APPEA Journal ◽

10.1071/aj15100 ◽

2016 ◽

Vol 56 (2) ◽

pp. 594

Author(s):

Lisa Hall ◽

Tehani Palu ◽

Chris Boreham ◽

Dianne Edwards ◽

Tony Hill ◽

...

Keyword(s):

Spatial Distribution ◽

Source Rock ◽

Sedimentary Basins ◽

Source Rocks ◽

Predictive Tool ◽

Resource Potential ◽

Petroleum Systems ◽

Petroleum Resource ◽

Hydrocarbon Yield ◽

Cooper Basin

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

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Geochemical characterization of the source rock intervals, Beni-Suef Basin, West Nile Valley, Egypt

Open Geosciences ◽

10.1515/geo-2020-0306 ◽

2021 ◽

Vol 13 (1) ◽

pp. 1536-1551

Author(s):

Nader A. A. Edress ◽

Saudy Darwish ◽

Amir Ismail

Keyword(s):

Heat Flow ◽

Source Rock ◽

High Heat ◽

Source Rocks ◽

Nile Valley ◽

Peak Oil ◽

Burial History ◽

Depth Limit ◽

Oil Generation ◽

Rock Depth

Abstract Geochemical and lithological investigations in the WON C-3X well record five organic-matter-rich intervals (OMRIs) of effective source rocks. These OMRIs correspond to moderate and good potentials. Two of these intervals occurred within the L-Kharita member of the Albian age represent 60.97% of the entire Albian thickness. The rest of OMRIs belongs to the Abu-Roash G and F members of the Late Cenomanian–Santonian age comprising 17.52 and 78.66% of their total thickness, respectively. The calculated heat flow of the studied basin is high within the range of 90.1–95.55 mW/m2 from shallower Abu-Roash F to deeper L-Kharita members. This high-heat flow is efficient for shallowing in the maximum threshold expulsion depth in the studied well to 2,000 m and active source rock depth limit to 2,750 m. Thermal maturity and burial history show that the source rock of L-Kharita entered the oil generation from 97 Ma till the late oil stage of 7.5 Ma, whereas the younger Abu-Roash G and F members have entered oil generation since 56 Ma and not reached peak oil yet. Hence, the source rock intervals from Abu-Roash F and G are promising for adequate oil generation.

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Thermal Effects of Magmatism on Surrounding Sediments and Petroleum Systems in the Northern Offshore Taranaki Basin, New Zealand

Geosciences ◽

10.3390/geosciences9070288 ◽

2019 ◽

Vol 9 (7) ◽

pp. 288 ◽

Cited By ~ 1

Author(s):

Anna Kutovaya ◽

Karsten F. Kroeger ◽

Hannu Seebeck ◽

Stefan Back ◽

Ralf Littke

Keyword(s):

New Zealand ◽

Source Rock ◽

3D Models ◽

Local Effect ◽

Magmatic Activity ◽

Burial History ◽

Negative Effects ◽

Oil Accumulation ◽

Petroleum Systems ◽

The Impact

In the past two decades, numerical forward modeling of petroleum systems has been extensively used in exploration geology. However, modeling of petroleum systems influenced by magmatic activity has not been a common practice, because it is often associated with additional uncertainties and thus is a high risk associated with exploration. Subsurface processes associated with volcanic activity extensively influence all the elements of petroleum systems and may have positive and negative effects on hydrocarbon formation and accumulation. This study integrates 3D seismic data, geochemical and well data to build detailed 1D and 3D models of the Kora Volcano—a buried Miocene arc volcano in the northern Taranaki Basin, New Zealand. It examines the impact of magmatism on the source rock maturation and burial history in the northern Taranaki Basin. The Kora field contains a sub-commercial oil accumulation in volcanoclastic rocks that has been encountered by a well drilled on the flank of the volcano. By comparing the results of distinct models, we concluded that magmatic activity had a local effect on the thermal regime in the study area and resulted in rapid thermal maturation of the surrounding organic matter-rich sediments. Scenarios of the magmatic activity age (18, 11 and 8 Ma) show that the re-equilibration of the temperature after intrusion takes longer (up to 5 Ma) in the scenarios with a younger emplacement age (8 Ma) due to an added insulation effect of the thicker overburden. Results of the modeling also suggest that most hydrocarbons expelled from the source rock during this magmatic event escaped to the surface due to the absence of a proper seal rock at that time.

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

Netherlands Journal of Geosciences – Geologie en Mijnbouw ◽

10.1017/s0016774600000378 ◽

2012 ◽

Vol 91 (4) ◽

pp. 535-554 ◽

Cited By ~ 5

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.

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Source Rock Distribution and Thermal Maturity in the Southern Arabian Peninsula

GeoArabia ◽

10.2113/geoarabia0303339 ◽

1998 ◽

Vol 3 (3) ◽

pp. 339-356

Author(s):

Penelope A. Milner

Keyword(s):

Saudi Arabia ◽

United Arab Emirates ◽

Source Rock ◽

Structural Model ◽

Oil And Gas ◽

Arabian Peninsula ◽

Source Rocks ◽

Burial History ◽

The North ◽

And Migration

ABSTRACT Recent work by Phillips Petroleum in the Southern Arabian Peninsula has elucidated the source potential of the Palaeozoic strata. A group of newly drilled and older wells, together with exclusive and non-exclusive reports, have been used in order to develop improved maturation and migration models for emerging plays, and to gain a better understanding of the subsidence and maturation history of this large and diverse area. It has been possible to conduct comprehensive burial history modelling for a number of wells from Oman, Saudi Arabia and the United Arab Emirates. This, together with the modelling of hypothetical wells derived from depth structure maps, has improved our understanding of oil- and gas-prone source rocks in the Cretaceous, Jurassic and Palaeozoic strata. The resultant maturity distribution has been developed with the aid of a more detailed structural model for the Southern Arabian Peninsula. In tandem with this study, available cores and cuttings were analysed to measure source rock total organic carbon, maturity and richness parameters and summarised using proprietary techniques. It is concluded that the Jurassic Hanifa Formation is less mature and not source facies to the south and west of the Rub’ Al-Khali. The oil and gas mature source facies is present in the north and east of the Rub’ Al-Khali and in the Western Emirates. In addition, it is concluded that the oil mature Silurian source facies is confined to the narrow southern and western margins of the Rub’ Al-Khali. Outside this area the overmature area is in the core of the Rub’ Al-Khali extending northeast to the United Arab Emirates. The remaining area is modelled as gas mature in western Saudi Arabia and Qatar.

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GEOCHEMICAL AND COMPOUND SPECIFIC CARBON ISOTOPIC CHARACTERISATION OF FLUID INCLUSION OILS FROM THE OFFSHORE PERTH BASIN,WESTERN AUSTRALIA: IMPLICATIONS FOR RECOGNISING EFFECTIVE OIL SOURCE ROCKS

The APPEA Journal ◽

10.1071/aj03008 ◽

2004 ◽

Vol 44 (1) ◽

pp. 223 ◽

Cited By ~ 4

Author(s):

H. Volk ◽

S.C. George ◽

C.J. Boreham ◽

R.H. Kempton

Keyword(s):

Organic Matter ◽

Fluid Inclusion ◽

Source Rock ◽

Early Cretaceous ◽

Source Rocks ◽

Molecular Evidence ◽

Terrestrial Organic Matter ◽

Carbon Isotopic ◽

Oil Source ◽

Coal Measures

The molecular composition of fluid inclusion (FI) oils from Leander Reef–1, Houtman–1 and Gage Roads–2 provide evidence of the origin of palaeo-oil accumulations in the offshore Perth Basin. These data are complemented by compound specific isotope (CSI) profiles of n-alkanes for the Leander Reef–1 and Houtman–1 samples, which were acquired on purified n-alkane fractions gained by micro-fractionation of lean FI oil samples, showing the technical feasibility of this technique. The Leander Reef–1 FI oil from the top Carynginia Formation shares many biomarker similarities with oils from the Dongara and Yardarino oilfields, which have been correlated with the Early Triassic Kockatea Shale. The heavier isotopic values for the C15-C25 n-alkanes in the Leander Reef–1 FI oil indicate, however, that it is a mixture, and suggest that the main part of this oil (~90%) was sourced from the more terrestrial and isotopically heavier Early Permian Carynginia Formation or Irwin River Coal Measures. This insight would have been precluded when looking at molecular evidence alone. The Houtman–1 FI oil from the top Cattamarra Coal Measures (Middle Jurassic) was sourced from a clay-rich, low sulphur source rock with a significant input of terrestrial organic matter, deposited under oxic to sub-oxic conditions. Biomarkers suggest sourcing from a more prokaryotic-dominated facies than for the other FI oils, possibly a saline lagoon. The Houtman–1 FI oil δ13C CSI n-alkane data are similar to those acquired on the Walyering–2 oil. Possible lacustrine sources may exist in the Early Jurassic Eneabba Formation and are present in the Late Jurassic Yarragadee Formation. The low maturity Gage Roads–2 FI oil from the Carnac Formation (Early Cretaceous) was derived from a strongly terrestrial, non-marine source rock containing a high proportion of Araucariacean-type conifer organic matter. It has some geochemical differences to the presently reservoired oil in Gage Roads–1, and was probably sourced from the Early Cretaceous Parmelia Formation.

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Petroleum source rocks of Western Australia

The APPEA Journal ◽

10.1071/aj17051 ◽

2018 ◽

Vol 58 (1) ◽

pp. 282 ◽

Cited By ~ 1

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.

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