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Benzonaphthothiophene (BNT) ratio (benzonaphtho[2,1-d]thiophene/benzonaphtho[1,2-d]thiophene) for five oil fields in Saudi Arabia, was measured and integrated with benzocarbazole ratio (BCR, benzo[a]carbazole/benzo[c]carbazole) and other geochemical data to track migration pathways and reduce charge risk. To improve analytical resolution, the sulfur-containing heterocycles were separated from the aromatic hydrocarbons using palladium(II)-bonded silica column prior to gas chromatography–mass spectrometry. The API gravity varies from 34.6° in the northernmost deepest field A to 14.7° in field E located 5000 ft (1524 m) shallower and 150 km to the south. This southward-shallowing trend is accompanied by a drop in the BNT ratio from 5.49 (field A) to 1.89 (field E). A common source kitchen and a narrow maturity range (0.78–0.84% calculated vitrinite reflectance), together with the lack of any evidence for biodegradation, collectively suggest that the observed fluid property variations in this petroleum system are controlled mainly by geochromatographic fractionation during migration. This is further attested by similarly decreasing BCR from 1.09 to 0.24, in agreement with southward migration. In comparison with the BCR, the BNT ratio shows wider variations with depth and relative migration distances, attesting to its value in tracking migration and reducing charge risk, especially in fluids that lack carbazole derivatives.

The Lower Silurian Qusaiba Hot Shales (QHS) are proven source rocks for oil within the Paleozoic, and possibly some of the Mesozoic, reservoirs in Saudi Arabia. Moreover, these shales have oil shale potential where they are immature and shallow enough for mining, as well as unconventional shale oil and shale gas potential, in areas where they are within oil-maturity and gas-maturity levels, respectively. The QHS were deposited in relatively shallow marine environments under anoxic water conditions, resulting in accumulation of amorphous kerogen, organic-walled graptolites and acritarchs. Across the Arabian Basin, organic matter quality does not show much variation for the QHS, but the maturity varies greatly as a result of varying burial history. Thermal maturity assessment of shale source rocks that lack vitrinite, such as the Qusaiba Hot shales, continues to be challenging, especially where conflicting measurements are obtained from different sources. This paper presents an integrated assessment of QHS thermal maturity parameters, based on cores from 13 carefully selected boreholes that – based on regional basin models – are believed to cover a wide maturity range (ca. 0.5 to 2.0% Ro). We conducted some analyses on kerogen (maceral petrography, graptolite reflectance, UV-fluorescence, whole rock pyrolysis, Raman spectroscopy of graptolite) and other analyses on bitumen extracts (GC and GC–MS of saturate and aromatic fractions, and FTIR spectroscopy of the asphaltene fraction). We show that using many thermal maturity parameters reduces uncertainty significantly, and we therefore recommend that graptolite reflectance analyses should be conducted in support of other maturity indicators. Proper reflectivity measurements of the graptolites set the reference for comparison of other maturity parameters obtained from petrographic, geochemical, and spectroscopic techniques. Our work provides a template by which Qusaiba thermal maturity can be more accurately estimated when only a limited set of maturity parameters is available.

The Carboniferous-Permian Unayzah gas condensate reservoir of the Ghazal Field in eastern Saudi Arabia contains abundant oil inclusions indicative of a palaeo-oil column. The molecular composition of a fluid inclusion rich zone at the top of the reservoir revealed a mid-mature biomarker distribution (0.80% vitrinite reflectance equivalent, VRE) that is considerably lower than that of the co-occurring reservoired fluid (1.41% VRE). Side chain cracking of the triaromatic steroids evident in the produced condensate is significantly less advanced in the inclusion oil, as is also reflected in their alkylnaphthalene distributions. The lower maturity signal in the inclusion oil is combined with calcareous related biomarkers that include relatively abundant 30-nor-17α-hopane, C24 tetracyclic terpane and alkyldibenzothiophenes, in contrast to the reservoir hydrocarbon fluid derived from the Lower Silurian Qusaiba shale. Inclusion gas is enriched in the higher hydrocarbons, which might be attributed to a high proportion of oil (or wet gas) inclusions. Fluid inclusion ethane and propane δ13C are very close to the mean of the produced gases, but carbon dioxide δ13C is about 5‰, and methane δ13C 2‰ less negative than the average of the produced Ghazal gases, which may signify more than one hydrocarbon generation/population within the fluid inclusions. An earlier contribution into the Unayzah reservoir from a non-Qusaiba source may therefore be inferred to have had preceded the volumetrically more significant and more mature Qusaiba charges. Further research is needed to elucidate the source of this oil charge and its extent, which could include deep (Cambrian or Neoproterozoic) sources that might be present in the region.

The unpredicted discovery of downdip oil in Permian–Carboniferous Unayzah sandstone reservoirs along the southern flank of the predominantly gas condensate Ghazal field in Saudi Arabia highlighted the need for a thorough assessment of controls on hydrocarbon properties, with the aim to improve prediction and reduce uncertainty. Primary controls on hydrocarbon property variations (condensate-to-gas ratio) here appear to be compartmentalization, multiple charging, presumably from a Lower Silurian Qusaiba kitchen to the south and east within the late-oil to wet-gas generation window, and dysmigration to the north and west. Gas on production represents mostly unmixed thermogenic accumulations of variable maturities, with no sign of biodegradation or thermal cracking. Light oil (1.06–1.21% calculated vitrinite reflectance [Rc]) in the southern part of the field represent late-mature accumulations that apparently escaped flushing by subsequent gas condensate charges generated near the wet-gas generation window (1.41–1.55% Rc) and currently occupying the field to the north. Constant maturity variations for both gasoline range and heavier components in each sample testify to a lack of mixing between the hydrocarbon phases. Petroleum inclusions similarly comprise either light oil or gas condensate that coexist with significantly overlapping homogenization temperatures, suggesting considerable overlap in their trapping history (135–35 Ma). Less mature petroleum has not been identified in the field, possibly because of a lack of trap closure or migration focus prior to the inferred Late Jurassic filling or because of displacement to updip structures, thereby high grading the probability of undiscovered oil west and northwest of Ghazal. If thermal generation instead of retrograde condensation or phase separation controls this petroleum system, then the potential for deeper oil accumulations is limited.

Stepwise extraction and molecular analysis of non-recoverable oil from intact reservoir core plugs is used to provide constraints on the accumulation history of petroleum in the Permo-Carboniferous Unayzah reservoirs at the Ghazal Field, Saudi Arabia. When integrated with existing tools such as oil geochemistry, gas geochemistry, stable carbon isotopes, fluid inclusions and thermal modeling, the sequential extraction approach helped decode a previously unrecognized component of the hydrocarbon accumulation history. In particular, it indicates that the region received early petroleum charges that were less mature than currently produced light oil and gas condensates, possibly from the prolific Early Silurian Qusaiba shale source rock and other sources. This has significant implications for prospecting for additional oil, particularly in the north/northwest of the Ghazal region where paleo-oil accumulations may have been displaced or spilled. The lower portion of the Unayzah reservoir (Unayzah-C) remained water-wet during early filling of the upper reservoir unit (Unayzah-A) and appears to have been filled only by a late oil charge. Anomalous molecular and carbon isotopic behavior of residual oil extracts from the uppermost segment of the Unayzah reservoir, where the free oil (first of the sequential extracts) is less mature (0.95% Rc) and isotopically lighter (δ13C−31.15‰) than the adsorbed oil (last sequential extract, 1.05% Rc; δ13C−29.65‰), suggests a late oil contribution or bitumen contamination from the overlying Khuff Formation.

A novel approach, based on geotracer compositional correlation analysis is reported, which reveals the oil charge sequence and migration pathways for five oil fields in Saudi Arabia. The geotracers utilised are carbazoles, a family of neutral pyrrolic nitrogen compounds known to occur naturally in crude oils. The approach is based on the concept that closely related fields, with respect to filling sequence, will show a higher carbazole compositional correlation, than those fields that are less related. That is, carbazole compositional correlation coefficients can quantify the charge and filling relationships among different fields. Consequently, oil migration pathways can be defined based on the established filling relationships. The compositional correlation coefficients of isomers of C1 and C2 carbazoles, and benzo[a]carbazole for all different combination pairs of the five fields were found to vary extremely widely (0.28 to 0.94). A wide range of compositional correlation coefficients allows adequate differentiation of separate filling relationships. Based on the established filling relationships, three distinct migration pathways were inferred, with each apparently being charged from a different part of a common source kitchen. The recognition of these charge and migration pathways will greatly aid the search for new accumulations.

Organic matter preserved in marine mudstones from three late Neoproterozoic depocentres – the Officer and Amadeus Basins and the Adelaide Fold Belt – was examined using standard microscopic and geochemical methods, including gas chromatography-mass spectrometry (GC–MS). Total organic carbon (TOC) contents of these sediments are typically low (

The phosphorite and the overlying ‘oil shale’ succession in central and eastern Jordan has been studied for its organic matter composition, maturation, hydrocarbon potential and sedimentological implications. Pristine phosphorite was authigenically precipitated from interstitial solutions in ventilated environments. Later they were reworked and winnowed to produced the granular phosphorites possibly as wave or storm sand bodies. The oil shale was deposited in the same basins where restricted water circulation and subsequent hypersalinity led to more reducing conditions and better organic matter preservation. Both facies represent a high bio-productivity regime associated with paleo-upwelling on the shallow, southern epicontinental shelf of the Tethys Ocean. The organic matter is dominantly amorphous and the extractable part is high. Kerogen is Type II-S to Type III. All maturity parameters investigated proved it to be immature (e.g. R0

Artificial mixing of two non-marine oils (one Permian and the other Jurassic) from the Cooper and Eromanga Basins, Australia was employed to assess the degree of co-mingling in reservoirs of the latter basin, and to verify estimates of mixing ratios based on a simple mass-balance approach using absolute concentrations of individual aromatic hydrocarbons. A cross-plot of the methylphenanthrene ratios 1-MP/9-MP and 2-MP/1-MP, already shown to be useful for recognising dual-sourced oil pools, has been re-calibrated against the model mixing curves (both ‘artificial’ and ‘theoretical’) obtained for experimental blends of the two end-member oils. Both curves reveal that previous attempts to identify the sources of mixed oils in this petroleum province using di- and tri-aromatic hydrocarbons seriously overestimate the Eromanga (Jurassic–Cretaceous) contribution. Samples plotting away from the model curves are likely to be mixtures of oils with maturities different to those of the end-members used in this experiment (Jurassic 0.52% Rc; Permian 1.00% Rc). The observed increase in thermal maturity (Rc) of the mixed oil as its Permian contribution increases casts doubt on the validity of distinguishing oil origins using only the maturity contrast between the Cooper and Eromanga petroleum systems.

The Murteree Ridge is a focus for up-dip migration from two major hydrocarbon kitchens within the intracratonic Cooper (Carboniferous–Triassic) and Eromanga (Jurassic–Cretaceous) Basins of South Australia. The accumulation histories of nine oil fields along and adjacent to the ridge have been reconstructed by sequential solvent extraction and analysis of residual oils in sandstone core plugs from their stacked reservoirs. Four Cretaceous reservoir units received multiple oil charges that varied widely in source affinity, from mostly Jurassic (and/or Cretaceous) to overwhelmingly Permian in origin. The distributions of residual oil saturations in live and palaeo-columns are consistent with the existence of two compartments, with the uppermost pools (Cadna-owie, Murta) showing the highest Permian inputs. These accumulations represent the earliest escape of low-maturity Cooper-sourced oil into overlying Eromanga strata. This initial charge was displaced upwards into the shallower traps by subsequent hydrocarbon pulses. Three separate Permian-charge episodes can be recognised. The corresponding DST oils (0.6–0.7% Rc) represent either the compositional average of all charges to their respective reservoirs, or a continuation of the alternating filling pattern observed for successive charges. Oils in the Hutton (Jurassic) reservoir of the outlying Kerrina and Mudlalee Fields to the northeast appear to be mixtures of two distinct Early Permian oil families, variably co-mingled with locally derived Jurassic and possibly Cambrian hydrocarbons.