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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.

Organic-rich Mississippian carbonates and oil samples from wells completed in the Mississippian and Woodford zones in northern Oklahoma were sampled and geochemically assessed to evaluate charge history. Rock and oil samples were collected from the Cherokee platform and the Anadarko shelf. Samples were analyzed using gas chromatography and gas chromatography-mass spectrometry (GC-MS) techniques for quantitative analysis of diamondoids and saturate and aromatic biomarkers. Results indicate Mississippian hydrocarbon source rocks have generation potential and reached the early oil window thermal maturity. Extracted bitumen from Mississippian rocks and related oils show unique biomarker signatures such as the presence of extended tricyclic terpanes and high input of C27 relative to C28 and C29 in regular and rearranged steranes. The extent of cracking, as measured by diamondoids, reveals a dramatic change in diamondoids concentration between areas east and west, respectively, of the Nemaha uplift. The higher concentration of diamondoids and biomarkers observed west of the Nemaha uplift indicates mixing of uncracked oil with cracked oil migrating out of the Anadarko Basin. This mix of uncracked and cracked oils west of the uplift suggests episodic hydrocarbon charge and a long-distance component to the migration model. In contrast, the Mississippian samples from east of the Nemaha uplift are depleted in diamondoids, suggesting limited migration distance and localized hydrocarbon generation under lower thermal stress.

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.

Several series of branched alkanes with quaternary carbon centers have been detected by GC–MS in the saturated hydrocarbon fractions of Neoproterozoic sedimentary rocks associated with fossilised microbial mats (Officer Basin, South Australia) and of shallow water carbonates (Spitsbergen, East Greenland and Baffin Island, Canada). A series of 5,5-diethylalkanes was predominant in most of these sediments and was typically accompanied by related series in lower abundance which, based on mass spectral characteristics, are tentatively assigned as 6,6-diethylalkanes, 5-butyl, 5-ethylalkanes and 6-butyl, 6-ethylalkanes. Each series displays strong odd or even carbon number preferences. Several of the sediments contained additional series of structurally undefined C3n alkanes, notable for very negative retention time factors which become more negative with increasing molecular weight—indicating that branching increases with each C3 addition. The strongly sequential carbon preference of the respective C2n and C3n branched alkane series, and a predominantly light 13C signature of the 5,5-diethylalkanes (cf. co-occurring n-alkanes), are consistent with an origin from organisms with a distinct physiology and/or carbon source. The relatively wide occurrence and high abundance of these branched alkanes in Proterozoic sediments containing benthic microbial mats suggests a relationship with specific paleoenvironmental conditions, for example strong water column redox gradients, that may have been more prevalent than in the Phanerozoic.

The high abundance with which tricyclic terpenoids have previously been detected in Tasmanite oil shales has led to the strong suspicion that the source of these compounds is the Tasmanites microfossil prevalent in these oil shales. In this study, the hydrocarbon composition of a Tasmanite oil shale and isolated Tasmanites were separately investigated by laser micropyrolysis gas chromatography–mass spectrometry, a recently developed technique that facilitates the analysis of small samples such as microfossils. Major products comprised C19–C28 tricyclic terpanes, including the ubiquitous 13-methyl, 14-alkylpodocarpanes, as well as a number of additional tricyclic terpane isomers, a C19 monoaromatic hydrocarbon, and several C19–C21 tricyclic terpenes (one and two orders of unsaturation). There have been few previous reports on the tricyclic terpenes and their production is likely attributable to the pyrolytic cleavage of analogous (probably saturated) tricyclic precursors within the macromolecular biopolymer. The only major difference between the tricyclic terpenoid compositions observed from these samples was the absence of the less concentrated oil shale products in the Tasmanites analyses, probably due to the lower organic content of the preextracted fossil. The very similar tricyclic content of both samples strongly supports the proposal of an inherent relationship between the Tasmanites and tricyclic terpenoid production. The integrity of the laser data was confirmed by comparison to a conventional data set obtained by the pyroprobe pyrolysis of the Tasmanite oil shale.

A range of well-preserved Neoproterozoic acanthomorph and sphaeromorph acritarchs from the Australian Centralian Superbasin have been individually analysed by combined microscopic and chemical methods. The acanthomorph acritarchs generally exhibit two or more cell wall categories and have fine laminations with no obvious trilaminar sheath structure, whereas the sphaeromorph acritarchs are characterised by a single cell wall structure with no distinct laminations. The significant organic carbon content of the acritarchs is evident by the EDS analysis. Petrological indices (Thermal Alteration Index⩽2.8, and strong yellow fluorescence) suggest a low thermal maturity for both coexisting acritarch groups. The biomarker composition of the enclosing-rock is similarly indicative of low thermal maturity, although most of the rock extract has probably originated from other sources including the lipid fraction of the acritarchs' cell membrane and cytoplasm rather than the preserved cell walls. In contrast, however, very limited chemical data was obtained directly from the morphologically-preserved component of the acritarchs by micro-FTIR and pyrolysis GC–MS analyses, and these results are consistent with a polyaromatic biomacromolecule of high recalcitrance. A large signal attributable to significant carbon-ordering — a characteristic of polyaromatic structures — was detected by laser micro-Raman spectroscopy. A unique ultrastructural and molecular entity of the studied Neoproterozoic acritarchs is indicated although a distinct fibrillar multilayered wall and a condensed polyaromatic macromolecular structure suggest a possible link between acanthomorph taxa and dinoflagellates. The contrasting maturity values indicated by the respective petrographic and chemical data highlight the need for a more rigorous correlation of these different maturity parameters.

Two taxa of Neoproterozoic acritarchs of unknown affinity, Multifronsphaeridium pelorium and Species A, are analysed by electron microscopic (SEM, TEM) and chemical (micro-FTIR, pyrolysis GC–MS, thermal desorption–MS) methods. Both acritarch species are characterised by multi-branched processes and a remnant trilaminar sheath (TLS) structure. The TLS-bearing wall structures in these acritarchs suggest a possible biological affinity to chlorophyte algaenan. The molecular data obtained from the two acritarchs were generally similar and also consistent with a chlorophycean affinity. A significant aliphatic moiety is evident in these acritarchs as a short-chain series of n -alkene/alkane pyrolysates and prominent aliphatic IR bands. The restricted molecular-weight range ( 20 ) of the n -alkene/alkane doublets and the lack of isoprenoid and other branched alkanes in the pyrolysates suggest a low degree of branching in the aliphatic component of these acritarch macromolecules. The significant methyl (CH 3 ) IR signal was attributed to the terminal groups of short n -alkyl moieties. Alkylbenzenes, alkylphenols and alkylindoles were also significant pyrolysis products, indicating an aromatic component, although the latter two components may be attributed to artificially- and/or diagenetically-formed melanoidin moieties. The macromolecular structure of Multifronsphaeridium sp. and Species A consists of short n -alkylpolymethylenic chains, probably linked via ether/ester bonds, with possibly a small aromatic content. This study presents ultrastructural and molecular evidence of a genetic relationship between Neoproterozoic acritarchs and Chlorophyceae.

With the aim to improve prediction and reduce uncertainty following a number of unexpected results from drilling, an integrated geological-geochemical-modelling approach was employed to untangle a complex filling history in a predominantly gas-producing Palaeozoic system of Saudi Arabia. The occurrence of light oil of variable condensate-to-gas ratios (CGR) both below and above the fieldwide gas-water contact in the Permo-Carboniferous Unayzah reservoir at the Ghazal field precludes a simple oil-rim setting. Gas-washing, water-washing, biodegradation, oil dropout, and source kitchen variations can all be excluded from exerting major control on CGR, which, instead, appears to be primarily a function of differential charging and discharging, as well as compartmentalization. Whether the basin received petroleum heavier or less mature than that currently being produced (40° - 50° API; calculated vitrinite reflectance, Rc ≥ 1.1%), and the likely fate of that oil remained open to speculation. Fluid inclusions contain only light oil and gas condensate with no evidence for heavier oil. The lack of heavier oil in these inclusions perhaps relate to reservoir temperature ( insufficient to form a significant amount of inclusions of early oil prior to the Late Jurassic. This may partly explain the paradoxically long lag between the inferred onset of black oil generation (Triassic) and light oil accumulation inferred from co-existing aqueous inclusions to have started in the Late Jurassic. Nonetheless, sequential extraction of traces of residual oil adsorbed onto mineral surfaces or trapped in smaller pores provided temporal resolution of oil charges, including evidence for the “missing” oil, with maturities as low as 0.89% Rc. These results (1) dispute the belief that less mature oil was never expelled from the source rock and (2) suggest the presence of active migration pathways, at least over Ghazal, in Late Jurassic. The presence of a trap at that time is only weakly supported from palinspastic reconstruction, and may need better refined mapping of the overburden. Given the regional geology and maturity trends that suggest charging from south and east, shallower or updip structures located to the west and northwest — where paleo-oil accumulations may have been displaced or spilled — are a good prospect for additional oil.

Reservoired oil is usually a mixture of multiple discrete petroleum charges. Unravelling the contribution and character of each charge is amongst the most daring challenges in petroleum geochemistry. This paper describes an approach that involves the evaluation of both free and residual oils to reconstruct the history of petroleum accumulation within the multireservoir Gidgealpa Field, located in the Cooper and Eromanga Basins of central Australia. Porewall-coating residual oils form by reservoir wetting processes and grow continuously by adsorption of polar compounds, retaining molecular information on the first oil that was present in the pore system. Such sequentially recovered residual oils proved useful in reconstructing the record of oil charges to the Gidgealpa Ridge. Using Araucariacaean markers for source discrimination and the benzocarbazole a/(a + c) ratio (BCR) for identification of the source region, five discrete charging events were distinguished. In contrast to most previous studies, benzocarbazole distributions were found to be independent of lithofacies, organic facies and maturity. However, alkylated carbazoles did exhibit a pronounced facies dependency. The application of alkylcarbazoles as source markers in the study area provides the first evidence of the expulsion of petroleum from Cambrian marine source rocks in the underlying Warburton Basin. � 2007 Elsevier Ltd. All rights reserved.