Detection of palaeo-oil columns in the offshore northern Perth Basin: extension of the effective Permo-Triassic charge system

2011 ◽  
Vol 51 (1) ◽  
pp. 377 ◽  
Author(s):  
Richard Kempton ◽  
Se Gong ◽  
John Kennard ◽  
Herbert Volk ◽  
David Mills ◽  
...  
Keyword(s):  
Fluid Inclusion ◽  
Geochemical Data ◽  
Terrestrial Organic Matter ◽  
Oil Accumulation ◽  
Charge System ◽  
High Incidence ◽  
Turtle Dove ◽  
Wax Content ◽  
Tricyclic Terpanes ◽  
Hydrocarbon Charge

A widespread charge system for oil accumulation in the offshore northern Perth Basin, Western Australia, is revealed by specialised fluid inclusion technologies. Palaeo-oil columns are detected in about three of four exploration wells, including those at the Cliff Head, Dunsborough, Frankland and Perseverance fields, and in dry wells at Flying Foam–1, Hadda–1, Houtman–1, Leander Reef–1, Lilac–1, Livet–1, Mentelle–1 and Morangie–1. A high incidence of palaeo-oil charge into Permian reservoirs below the Kockatea Shale confirms that the conventional oil shows are, in part, residues of palaeo-oil. Oil migration is suggested at Vindara–1 and Leander Reef–1 and is below detection limits in Batavia–1, Charon–1, Fiddich–1 Geelvink–1A, Gun Island–1 and South Turtle Dove–1B, Twin Lions–1 and Wittecarra–1. New geochemical data from fluid inclusion oil at Hadda–1 shows evidence for a contribution from the Hovea Member of the Kockatea Shale, including: high wax content; low pristane/phytane ratio; high abundance of extended tricyclic terpanes; and, the highly diagnostic C33 n-alkylcyclohexane biomarker. This key component of the petroleum system acted as both source and seal, and extends further offshore than previously realised. Possible co-sourcing from terrestrial organic matter is indicated by high abundances of C29 steranes and diasteranes, C19 tricyclic, and C24 tetracyclic terpanes, which may be sourced from Permian rocks. The high incidence of palaeo-oil and residual columns suggests that trap integrity is likely to be an important preservation risk, with elements of gas displacement. Screening of prospects for structural and hydrocarbon charge characteristics, which are favourable for retention of oil, is key in future exploration of the offshore northern Perth Basin.

Geologic-geochemical and modelling studies of hydrocarbon migration in the South Caspian basin

2020 ◽  
pp. 4-15
Author(s):  
M.F. Tagiyev ◽  
◽  
I.N. Askerov ◽  
◽  
◽  
...  
Keyword(s):  
Sedimentary Cover ◽  
Geochemical Data ◽  
Caspian Basin ◽  
Hydrocarbon Generation ◽  
The South ◽  
South Caspian Basin ◽  
Hydrocarbon Migration ◽  
Upward Migration ◽  
Modelling Studies ◽  
Hydrocarbon Charge

Based on pyrolysis data an overview is given on the generative potential and maturity of individual stratigraphic units in the South Caspian sedimentary cover. Furthermore, the pyrolysis analyses indicate that the Lower Pliocene Productive Series being immature itself is likely to have received hydrocarbon charge from the underlying older strata. The present state of the art in studying hydrocarbon migration and the "source-accumulation" type relationship between source sediments and reservoired oils in the South Caspian basin are touched upon. The views of and geochemical arguments by different authors for charging the Lower Pliocene Productive Series reservoirs with hydrocarbons from the underlying Oligocene-Miocene source layers are presented. Quantitative aspects of hydrocarbon generation, fluid dynamics, and formation of anomalous temperature & pressure fields based on the results of basin modelling in Azerbaijan are considered. Based on geochemical data analysis and modelling studies, as well as honouring reports by other workers the importance and necessity of upward migration for hydrocarbon transfer from deep generation centers to reservoirs of the Productive Series are shown.

Hydrocarbon charge in the onshore Canning Basin: insights from quantitative fluorescence and fluid inclusion investigations

2011 ◽  
Vol 51 (2) ◽  
pp. 706
Author(s):  
Keyu Liu ◽  
Ameed Ghori ◽  
Richard Kempton ◽  
Peter Eadington ◽  
Stephen Fenton ◽  
...  
Keyword(s):  
Fluid Inclusion ◽  
Petroleum System ◽  
Spectral Signature ◽  
Depth Interval ◽  
Widespread Occurrence ◽  
Canning Basin ◽  
Group A ◽  
Multiple Reservoir ◽  
Hydrocarbon Charge ◽  
Quantitative Fluorescence

The vast and mostly onshore Canning Basin—with an area of approximately 595,000 m2—is the least explored onshore sedimentary basin in Australia. As part of the petroleum system assessment carried out by WA DMP, more than 160 samples were investigated from eight wells in the onshore Canning Basin—they are: Acacia-1 Dodonea-1 Dodonea-2 Lake Hevern-1 Looma-1 White Hill-1 Wilson Cliffs-1 Yulleroo-1. Fluid inclusion and quantitative fluorescence techniques developed by CSIRO were used, including: The grains containing oil inclusions (GOITM) technique; The quantitative grain fluorescence (QGF) technique; QGF on extracts (QGF-E); and, the total scanning fluorescence (TSF) technique. The results reveal a widespread occurrence of hydrocarbon shows in the reservoir intervals investigated—7–8 wells showed evidence of oil migration and/or accumulations often occurring at multiple depth intervals. In White Hill-1, elevated QGF and QGF-E responses were recorded in the sandy units in a depth interval of more than 500 m in the Fairfield Group. A residual or palaeo oil column of >20 m gross height at 1,655 m was apparent from the QGF and QGF-E depth profiles—and GOI and TSF data. Oil inclusions from the Fairfield Group in White Hill-1 show spectral signature typical of thermally mature and light-medium API gravity. The TSF results also indicate the presence of some condensate species, as well as relatively heavy and possibly bio-degraded oils. The new fluid inclusion and fluorescence data provide direct evidence of an active petroleum system in the Canning Basin at multiple reservoir intervals, which may be of local significant quantity.

scholarly journals Geochemical Data and Fluid Inclusion Study of the Middle Miocene Halite from Deep Borehole Huwniki-1, Situated in the Inner Zone of the Carpathian Foredeep in Poland

Minerals ◽  
2020 ◽  
Vol 10 (12) ◽  
pp. 1113
Author(s):  
Krzysztof Bukowski ◽  
Anatoliy Galamay ◽  
Piotr Krzywiec ◽  
Andrzej Maksym
Keyword(s):  
Fluid Inclusion ◽  
Fluid Inclusions ◽  
Fluid Inclusion Study ◽  
Geochemical Data ◽  
Sulfate Ions ◽  
Deep Well ◽  
Evolutionary Changes ◽  
Orogenic Wedge ◽  
Inclusion Study ◽  
Salinity Water

The geochemical data and the study of fluid inclusions in primary halite are invaluable sources of saline basin information. Most of the previous analyses of salt from the Carpathian area have been obtained by studying the halite samples collected from depths not exceeding 1000 m (i.e., from salt mine outcrops or boreholes). In this article, for the first time, we present the results of samples obtained from a deep well where salt occurs below the frontal orogenic wedge at a depth of ~5000 m. The salt core’s petrological studies showed, quite unexpectedly, the presence of the chevron relics, typical for primary halite. Their geochemical data and fluid inclusion study can be used to reconstruct the environment of the salt sedimentation. The bromine, strontium, and rubidium content values indicated that primary brines were of marine origin, and salts may have undergone partial dissolution and redeposition under lower salinity water inflows. The main ions’ (K, Mg, SO4) ratios in the fluid inclusions were typical for those of the Badenian brines collected from the Carpathian Foredeep’s eastern part. Compared with modern seawater’s chemical composition, this brine contained a slightly lower content of sulfate ions. This was associated with evolutionary changes occurring in the contents of sulfate ions during the Cenozoic.

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

2002 ◽  
Vol 42 (1) ◽  
pp. 387 ◽  
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.

COMPARISON OF PALAEO OIL CHARGES WITH CURRENTLY RESERVOIRED HYDROCARBONS USING MOLECULAR AND ISOTOPIC ANALYSES OF OIL-BEARING FLUID INCLUSIONS: JABIRU OIL FIELD, TIMOR SEA

1997 ◽  
Vol 37 (1) ◽  
pp. 490 ◽  
Author(s):  
S.C. George ◽  
P.F. Greenwood ◽  
G.A. Logan ◽  
R.A. Quezada ◽  
L.S.K. Pang ◽  
...  
Keyword(s):  
Fluid Inclusion ◽  
Fluid Inclusions ◽  
Hydrocarbon Composition ◽  
Polar Compounds ◽  
Oil Field ◽  
Geochemical Data ◽  
Peak Oil ◽  
Adsorption Effect ◽  
Isotopic Analyses ◽  
Oil Source

Geochemical techniques have been used to compare the composition of oil trapped in fluid inclusions from the Jabiru oil field with currently reservoired oil. The inclusion oil is preferentially enriched in polar compounds, probably due to an adsorption effect during trapping, but this has not affected the hydrocarbon composition of the trapped oil. Source characterisation using biomarker and gasoline range hydrocarbon parameters shows that the fluid inclusion oils have the same source affinity as the current production oil. This is corroborated by the carbon isotopic compositions of high molecuJar weight n-alkanes trapped in oil-bearing fluid inclusions, which are similar to those of the production oil. Both oils have maturities in the peak oil generative window, but aromatic hydrocarbon ratios demonstrate that the fluid inclusion oil is less mature (calculated reflectance [RJ = 0.84 per cent) than the currently reservoired charge (0.92 per cent Rc). Fluid inclusion abundance data and residual oil saturations indicate the Jabiru oil column was previously significantly larger, with subsequent leakage reducing the column to its present size. The geochemical data collected for the fluid inclusion oil suggests that it is representative of early charge to the Jabiru structure. The difference between the fluid inclusion oil and the production oil is thought to reflect continued charging of the trap with progressively more mature oil from the same or similar source rock facies. The change in the molecular composition of the oil in the Jabiru structure probably occurred by dilution of earlier, lower maturity charge with larger volumes of more mature oil.

Organic geochemical characteristics of coal deposits in Mae Than coal mine, Lampang Province, Thailand

2020 ◽  
Author(s):  
Patthapong Chaiseanwang ◽  
Piyaphong Chenrai
Keyword(s):  
Organic Matter ◽  
Depositional Environment ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Terrestrial Organic Matter ◽  
Normal Alkanes ◽  
Lampang Province ◽  
Extractable Organic Matter ◽  
Organic Matter Input

<p>Fifteen samples were collected from coal mines Mae Than basins located in Lampang Province, Northern Thailand to investigate organic geochemical characterization which can provide organic matter input, thermal maturity and depositional environment. The total organic carbon (TOC) content of the coal samples ranges from 30.12 to 73.71 wt. %, while shales and mudstones value between 5.98 – 24.87 wt. %. The extractable organic matter (EOM) content of all samples, which is yielded from bitumen extraction, values in the range of 1,256 and 16,421 ppm indicating good to excellent hydrocarbon generation potential. The organic geochemical data were studied by using Gas-chromatography Mass-spectrometry (GC-MS) providincg biomarker and non-biomarker data. The thermal maturity of studied samples is represented as immature stage due to ratio of Ts/(Ts+Tm) and homohopane isomerization. The distribution of normal alkanes is predominantly long-chain normal alkanes with odd-numbered carbon. The high Carbon Preference Index (CPI) value of samples indicates terrestrial organic matter input. The depositional environment of the study area can be interpreted that the coal formation is occurred within an oxidizing condition with the majority of higher plant input, whereas shale and mudstone is slightly more anoxic-aquatic environment.</p>

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

2004 ◽  
Vol 44 (1) ◽  
pp. 223 ◽  
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.

Seawater composition during deposition of Viséan evaporites in the Moncton Subbasin of New Brunswick as inferred from the fluid inclusion study of halite

2002 ◽  
Vol 39 (2) ◽  
pp. 157-167 ◽  
Author(s):  
Oleh Petrychenko ◽  
Tadeusz Marek Peryt ◽  
Brian Roulston
Keyword(s):  
Chemical Composition ◽  
Fluid Inclusion ◽  
Gas Content ◽  
Fluid Inclusion Study ◽  
Geochemical Data ◽  
Eastern Canada ◽  
Stratigraphic Sequence ◽  
Inclusion Study ◽  
History Of ◽  
Maritimes Basin

The Viséan evaporites of the Windsor Group in the Moncton Subbasin at the western limit of the Maritimes Basin of eastern Canada represent an important stratigraphic sequence to study in determining changes in the chemistry of marine brines. Seventeen samples of halite have been selected for fluid inclusion study. The chemical composition of inclusion brines was examined using the Petrichenko method of glass capillaries with applied ultramicroanalytical techniques. The results of the study indicate that the conditions of evaporite deposition in the Windsor Basin differed from those recorded in other Phanerozoic basins and that the history of the Windsor Basin brines was characterized by changes in the chemical composition of the brines. It was also found that there existed continual unfavourable conditions for the day-and-night zonality in chevron halite crystals and for the origin of relatively large (>50 µm) fluid inclusions and that the gas content was low not only during the deposition but also during the diagenesis of potash deposits. The chemical composition of the Viséan waters of the Moncton Subbasin at the beginning and end of deposition of the Windsor Group evaporite sequence was controlled by the predominating waters of nonmarine origin; during the potash deposition the controlling factor was chloride-type marine waters. In general, the geochemical data support the concept of Carboniferous evaporite basins with Na–K–Mg–Ca–Cl-type brines.

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