INTEGRATED SOURCE, MATURATION AND MIGRATION ANALYSIS, GIPPSLAND BASIN, AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 313 ◽  
Author(s):  
P. S. Moore ◽  
B. J. Burns ◽  
J. K. Emmett ◽  
D. A. Guthrie
Keyword(s):  
Source Rocks ◽  
Source Distribution ◽  
Integrated Analysis ◽  
Peak Oil ◽  
Gas Generation ◽  
Southeastern Part ◽  
Migration Pathway ◽  
And Migration ◽  
Gippsland Basin ◽  
Migration Pathways

Biomarker geochemistry, maturation modelling and migration pathway analysis have been used in a new, integrated analysis of the Gippsland Basin. The analysis has resulted in the development of a predictive model for hydrocarbon charge and oil versus gas split. The study was carried out in 4 parts: analytical geochemistry, source distribution mapping, maturation modelling and migration pathway analysis.New geochemical biomarker studies confirm a non-marine source for the oils, but place peak oil generation in the upper part of the traditional oil window. Gas in the basin is mainly derived from overmature source rocks. Coals were recognised to contribute significantly to oil generation.The source rock thickness and distribution for the entire basin were mapped using analytical techniques plus wireline log analysis, coupled with seismic structural mapping and facies analysis. Prime oil-prone source rocks were found to be located in the lower coastal plain depositional environment. Extrapolations were necessary for older rocks, using stratigraphic models.Maturation modelling modelling of selected wells and synclines was carried out and an overall basin model constructed. Post-structuring yields of oil and gas were also derived. A key result was the lack of post-structuring overmature gas generation in the oil prone southeastern part of the basin, owing to high palaeo-temperatures associated with earlier rifting.Analysis of present day and palaeo-migration pathways gave an excellent match between predicted oil versus gas ratios and discoveries, both geographically and stratigraphically. The tool is now being used in a predictive mode to highgrade basin prospectivity.

scholarly journals Petroleum generation and migration in the Mesopotamian Basin and Zagros Fold Belt of Iraq: results from a basin-modeling study

GeoArabia ◽  
2004 ◽  
Vol 9 (4) ◽  
pp. 41-72 ◽  
Author(s):  
Janet K. Pitman ◽  
Douglas Steinshouer ◽  
Michael D. Lewan
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Peak Oil ◽  
Fold Belt ◽  
Hydrous Pyrolysis ◽  
Oil Generation ◽  
Petroleum Generation ◽  
And Migration ◽  
Migration Pathways

ABSTRACT A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.

PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 315 ◽  
Author(s):  
K. K. Romine ◽  
J. M. Durrant ◽  
D. L. Cathro ◽  
G. Bernardel
Keyword(s):  
Focal Point ◽  
Source Rocks ◽  
Predictive Tool ◽  
Petroleum Systems ◽  
The North ◽  
Northern Carnarvon Basin ◽  
And Migration ◽  
Play Elements ◽  
Migration Pathways ◽  
Carnarvon Basin

A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.

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.

ORIGIN OF PETROLEUM IN THE BOWEN AND SURAT BASINS: GEOCHEMISTRY REVISITED

1995 ◽  
Vol 35 (1) ◽  
pp. 579 ◽  
Author(s):  
C. J. Boreham
Keyword(s):  
Vitrinite Reflectance ◽  
Stable Carbon Isotope ◽  
Isotope Analysis ◽  
Source Rocks ◽  
Gas Generation ◽  
Delta Plain ◽  
The North ◽  
Biomarker Analysis ◽  
And Migration ◽  
A Minor

A detailed regional geochemical study of over 70 oils and condensates, eleven natural gases and over a hundred core samples from potential source rocks enable resolution of the generation and migration history of petroleum in the Bowen and Surat Basins. Biomarker analysis confirms a pre-Jurassic source for the petroleum. Stable carbon-isotope analysis further indicated a Permian-sourced petroleum and was able to differentiate a very minor and localised Triassic source contribution. The dominant source for the petroleum is terrestrial land plants as well as a minor contribution from bacteria and marine algae. In the north, Late Permian lower delta plain and alluvial Permian coals show the higher liquid potential compared with upper delta plain facies, while in the Taroom Trough, coals in the Blackwater Group have the highest liquid potential compared with mudrocks of the Blackwater Group, and sediments of the Back Creek Group. Initial liquid expulsion from the source rock occurred at vitrinite reflectance (Ro) of 0.65-0.7 per cent and continued to Ro of 1.05 per cent. This was followed by the main phase of gas generation between 1.05 per cent

scholarly journals The hydrocarbon potential of the offshore Talara Basin, Peru

2021 ◽  
Vol 49 (1) ◽  
Author(s):  
Eduardo Antonio Rossello ◽  
Stephen P.J. Cossey ◽  
Guzmán Fernández
Keyword(s):  
Active Continental Margin ◽  
Late Eocene ◽  
Source Rocks ◽  
3D Seismic ◽  
The North ◽  
Migration Pathway ◽  
The Andes ◽  
Bottom Simulating Reflectors ◽  
Productive Area ◽  
Migration Pathways

The offshore Talara Basin is the western extension of the hydrocarbon producing onshore fields since the mid-1800s area of Peru and is also located above the subduction zone of the active continental margin of South America. The offshore portion was evaluated using high quality 3D seismic where mapping horizons are all unconformities within the Eocene as well as the unconformities at the top Paleocene and top Cretaceous. Possible source rocks are the Cretaceous black marine shales of the Campanian Redondo Formation, the limestones of the Albian Muerto Formation, and the marine shales of the Paleogene. The primary target offshore is expected to be deep-water turbidites of Paleocene/Eocene age with a depositional source from the northeast from highlands created by the compressional uplift of the Andes. The main seals offshore are expected to be shales of the upper Eocene Lagunitos Formation and shales in the Chacra Formation, which are also seals in the onshore Litoral field. Thermal maturation modeling shows that two hydrocarbon kitchens exist in the offshore portion of the Talara basin, one in the north and one in the south. The probable Cretaceous source rocks reached the onset of maturity (VR = 0.63%) at a depth of 3,250 to 3,285 m (10,663 – 10,778 ft) between 30 and 39 Ma (Late Eocene to Oligocene). Importantly, the Cretaceous source rocks stay within the oil window once they enter it in the late Eocene. Satellite studies show a large offshore present-day oil seep in the southern part of the basin and 3D seismic shows direct hydrocarbon indicators (DHIs) imaged as flat spots and bottom simulating reflectors (BSR). Basin modeling suggests hydrocarbon migration pathways would have been updip (to the east) into the onshore traps and would therefore have first filled the offshore traps along the migration pathway. We conclude that the Talara Basin offshore offers excellent exploration opportunities in a proven productive area where multiple prospects have been mapped.

scholarly journals Petroleum system modeling in cenozoic sediments, Block 05-1a, Nam Con Son Basin

2017 ◽  
Vol 20 (K4) ◽  
pp. 91-102
Author(s):  
Xuan Van Tran ◽  
Huy Nhu Tran ◽  
Chuc Dinh Nguyen ◽  
Tuan Nguyen ◽  
Ngoc Ba Thai ◽  
...  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
System Modeling ◽  
Model Development ◽  
Source Rocks ◽  
Early Miocene ◽  
North East ◽  
Petroleum System Modeling ◽  
And Migration ◽  
Migration Pathways

Based on the update of exploration data the oil and gas potential within block 05-1 are studied through define the source rocks, Hydrocarbon (HC) generation, expulsion and migration, focusing on source rock Oligocene /Early Miocene and Middle Miocene; Define the accumulation of hydrocarbon in Lower Miocene targets; The results of assessments for source rock, oil sampling analysis is used to determine the relationship between in–situ oil or oil migrated from other places. The workflow of basin modeling is assigned to get output (migration pathways, volume of accumulation), as well as data calibration. Main source rocks include H150, H125 shales and H150 coal with Total organic carbon (TOC)~1 and 47 respectively. These source rocks are medium to good potential. At the present time, most of the source rocks are in oil window, while the deep parts is in gas window. Oil started to be generated in Early Miocene, and started to be expulsed in Late Miocene. Gas started to be generated in Quaternary, about to be expulsed. The oil migrated mainly from the troughs at the West and minorly from the East and South to Dai Hung High. Gas started to migrate from West to East and South West to North East at the Western part. However, at the Eastern part, gas migrated from the opposite direction. The results of sensitive analyses show more oil in max source rock case, therefore, a 3D model development is recommended and identify the differences in generation characteristics between Nam Con Son and Cuu Long basins.

scholarly journals A review of oil and gas seepage in the Nuussuaq Basin, West Greenland – implications for petroleum exploration

2020 ◽  
Author(s):  
Flemming G. Christiansen ◽  
Jørgen A. Bojesen-Koefoed ◽  
Gregers Dam ◽  
Troels Laier ◽  
Sara Salehi
Keyword(s):  
Structural Model ◽  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Lateral Migration ◽  
West Greenland ◽  
Gas Seepage ◽  
Petroleum Generation ◽  
And Migration ◽  
Migration Pathways

The Nuussuaq Basin in West Greenland has an obvious exploration potential. Most of the critical elements are well documented, including structures that could form traps, reservoir rocks, seals and oil and gas seepage that documents petroleum generation. And yet, we still lack a full understanding of the petroleum systems, especially the distribution of mature source rocks in the subsurface and the vertical and lateral migration of petroleum into traps. A recently proposed anticlinal structural model could be very interesting for exploration if evidence of source rocks and migration pathways can be found. In this paper, we review all existing, mostly unpublished, data on gas observations from Nuussuaq. Furthermore, we present new oil and gas seepage data from the vicinity of the anticline. Occurrence of gas within a few kilometres on both sides of the mapped anticline has a strong thermogenic fingerprint, suggesting an origin from oil-prone source rocks with a relatively low thermal maturity. Petroleum was extracted from an oil-stained hyaloclastite sample collected in the Aaffarsuaq valley in 2019, close to the anticline. Biomarker analyses revealed the oil to be a variety of the previously characterised “Niaqornaarsuk type,” reported to be formed from Campanian-age source rocks. Our new analysis places the “Niaqornaarsuk type” 10 km from previously documented occurrences and further supports the existence of Campanian age deposits developed in source rock facies in the region.

AGE DETERMINATION OF CRUDE OILS IN THE BARROW SUB- BASIN USING PALAEOCLIMATE RELATED VARIATIONS IN HIGHER PLANT BIOMARKERS

1999 ◽  
Vol 39 (1) ◽  
pp. 399
Author(s):  
B.G.K. van Aarssen ◽  
T.P. Bastow ◽  
R ◽  
Alexander ◽  
R.I. Kagi
Keyword(s):  
Source Rock ◽  
Age Groups ◽  
Age Determination ◽  
Source Rocks ◽  
Crude Oils ◽  
Higher Plant ◽  
Sedimentary Sequences ◽  
And Migration ◽  
Oil Source ◽  
Migration Pathways

Variations in higher-plant-derived biomarkers in sedimentary sequences reflect changes in the palaeoclimatic conditions at the time of deposition. It is thought that changes in climate affect the distribution of higher plant populations growing on the hinterland, thus changing the contribution of these plants into the sediments. These variations can be measured using the abundances of three aromatic hydrocarbons: retene, cadalene and iP-iHMN. This was done for a Jurassic sedimentary sequence from the Koolinda–1 well in the Barrow Sub-basin, The obtained profile was related to an absolute time-scale. Measurement of the higher-plant-derived biomarkers in crude oils from the Barrow Sub-basin enabled accurate measurement of the age of their source rocks by using the Koolinda–1 profile as a reference. Most of these oils correlate with the Jurassic W. spectabilis dinoflagellate zone in the Oxfordian. Within this zone the oils fall into four age groups, reflecting four oil-prone intervals each separated by approximately 0.2 My. The oils that have been generated from each group can be found in specific reservoirs in the sub-basin, showing a pattern of migration away from the depocentre with decreasing age of the source rock. This method of determining the source rock age of crude oils enables detailed oil-source rock correlations. On a basin-wide scale it can provide insight into the location of major source rocks and migration pathways.

ORIGIN OF GILMORE GAS AND OIL, ADAVALE BASIN, CENTRAL QUEENSLAND

1998 ◽  
Vol 38 (1) ◽  
pp. 399 ◽  
Author(s):  
C.J. Boreham ◽  
R.A. de Boer
Keyword(s):  
Oil And Gas ◽  
Isotope Composition ◽  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Gas Generation ◽  
Migration Pathway ◽  
Wet Gas ◽  
Modelling Studies ◽  
High Maturity

Dry gas in the Gilmore Field of the Adavale Basin has been sourced from both wet gas associated with oil generation, together with methane from a deep, overmature source. The latter gas input is further characterised by a high nitrogen content co-generated with isotopically heavy methane and carbon dioxide. The eastern margin of the Lissoy Sandstone principal reservoir unit contains the higher content of overmature dry gas supporting reservoir compiirtmenmlisalion and a more favourable migration pathway to this region. The combination of a molecular and multi-element isotopic approach is an effective tool for the recognition of an overmature, dry gas source. This deep source represents a play concept that previously has been undervalued and may be more widespread within Australian sedimentary basins.The maturity level of the wet gas and associated oil are identical, having reached an equivalent vitrinite reflectance of 1.4−1.6 per cent. Modelling studies support the concept of local Devonian source rocks for the wet gas and oil. Reservoir filling from late stage, high maturity oil and gas generation and expulsion, was a result of reactivation of petroleum generation from Devonian source rocks during the Early Cretaceous. The large input of dry gas from a deeper and highly overmature source is a more recent event. This gas can fractionally displace condensable C2+ liquids already in the reservoir possibly allowing tertiary migration into younger reservoirs, or adjacent structures.Oil recovered from Gilmore-2 has been sourced from Devonian marine organic matter, deposited under mildly evaporitic, restricted marine conditions. The most likely source rocks in the Adavale Basin are the basal marine shale of the Log Creek Formation, algal shales at the top of the Lissoy Sandstone, and the Cooladdi Dolomite. Source-sensitive biomarkers and carbon isotope composition of the Gilmore-2 oil have much in common with other Devonian-sourced oils from the Bonaparte and Canning basins. The chemical link between western and eastern Australian Devonian oils may suggest diachronous development of source rocks over a wide extent. This implies that the source element of the Devonian Petroleum Supersystem may be present in other sedimentary basins.

scholarly journals Natal origin and migration pathways of Mekong catfish (Pangasius krempfi) using strontium isotopes and trace element concentrations in environmental water and otoliths

PLoS ONE ◽  
2021 ◽  
Vol 16 (6) ◽  
pp. e0252769
Author(s):  
Ngan Trong Tran ◽  
Maylis Labonne ◽  
Ming-Tsung Chung ◽  
Chia-Hui Wang ◽  
Kuo-Fang Huang ◽  
...  
Keyword(s):  
Trace Element ◽  
Mekong Delta ◽  
Environmental Water ◽  
Mekong River ◽  
Migration Routes ◽  
Natal Origin ◽  
Element Concentrations ◽  
Migration Pathway ◽  
And Migration ◽  
Migration Pathways

To improve our knowledge of the migration pathway of a highly threatened fish species along the Mekong River, strontium isotope ratios (87Sr/86Sr) and 18 trace element concentrations were measured in the water and in the otoliths of an anadromous catfish, Pangasius krempfi, to infer its natal origin and potential migration pathways. Water was sampled at 18 locations along the mainstream, tributaries and distributaries of the Mekong River. To check for accuracy and precision, measurements of the 87Sr/86Sr ratios and trace element concentrations were then compared in two laboratories that use different analytical methods. Differences in trace element concentrations between locations were not significant and could not, therefore, be used to discriminate between migration pathways. However, the Mekong mainstream, tributaries and distributaries could all be discriminated using Sr isotopes. The 87Sr/86Sr profiles recorded in P. krempfi otoliths showed that there were three contingents with obligate freshwater hatching and variable spawning sites along the Mekong mainstream, from Phnom Penh (Cambodia) to Nong Khai (Thailand) or further. After hatching, the fish migrated more or less rapidly to the Mekong Delta and then settled for most of their lifetime in brackish water. Spawning habitats and migration routes may be threatened by habitat shifts and the increasing number of hydropower dams along the river, especially the contingents born above Khone Falls (Laos). The conservation of P. krempfi, as well as other migratory fish in the Mekong River, requires agreements, common actions and management by all countries along the Mekong River. This study highlighted the importance of using both Sr/Ca and 87Sr/86Sr ratios to understand life history of anadromous fishes as the 87Sr/86Sr ratio in the water was shown to be less effective than the Sr/Ca ratio in identifying movements between different saline areas.

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