Diamondoid Hydrocarbons Research Articles

Do distributions of diamondoid hydrocarbons accumulated in oil-contaminated fish tissues help to identify the sources of oil?

Identifying the sources of environmental oil contamination can be challenging, especially for oil in motile organisms such as fish. Lipophilic hydrocarbons from oil can bioaccumulate in fish adipose tissue and potentially provide a forensic “fingerprint” of the original oil. Herein, diamondoid hydrocarbon distributions were employed to provide such fingerprints. Indices produced from diamondoids were used to compare extracts from fish adipose tissues and the crude and fuel oils to which the fish were exposed under laboratory conditions. A suite of 20 diamondoids was found to have bioaccumulated in the dietary-exposed fish. Cross-plots of indices between fish and exposure oils were close to the ideal 1:1 relationship. Comparisons with diamondoid distributions of non-exposure oils produced overall, but not exclusively, weaker correlations. Linear Discriminatory Analysis on a combined set of 15 diamondoid and bicyclane molecular ratios was able to identify the exposure oils, so a use of both compound classes is preferable.

On the determination of oil charge history and the practical application of molecular maturity markers

Determining the thermal maturity and the charge history of crude oil to any reservoir, has key implications for understanding petroleum generation, accumulation history and hence identification of exploration potential. In this paper we combine studies of several source rock sequences and associated crude oils using quantitative component concentration data in addition to traditional molecular marker ratio parameter approaches. The case history studies include examination of organic-rich sapropelic marine source rocks from the Second White Speckled Shale Formation (2 WS Fm.), in the Western Canada Sedimentary Basin and the upper Jurassic Draupne Fm. in the North Sea and their related oils. Each molecular component in the petroleum has a unique concentration evolution curve during source rock maturation, in which n-alkanes, light aromatic hydrocarbons and diamondoid hydrocarbons increase in concentration with increasing maturity, while biomarkers decrease in concentration with maturity. This maturity dependent concentration variation plus the ubiquitous mixing of multiple oils in the reservoir is a key process that complicates the direct application of qualitative molecular marker ratio approaches to analysis of petroleum systems. We suggest an alternative maturity assessment approach using maturation calibrated curves of absolute concentrations of biomarkers and other alkanes in petroleum, coupled with selected aromatic hydrocarbon ratios to track the maturity/petroleum mass fraction relationships for a reservoired oil mixture in a more complex but realistic manner. Isoprenoid alkanes show less variation in concentration with maturity than other components and may be used as an internal reference point for mass fraction maturity and charge history assessment. Using component concentration data normalized to the concentration of the isoprenoid alkanes and calibrated using source rock analyses at different maturity levels from a single petroleum system (2WS), a simple mass balance model was constructed that allowed aggregate concentration data to be calculated for any mixture of oils produced in a prescribed oil charge history. In principle any charge history can be simulated using this approach and comparing the modelled and actual quantitative compositional profiles of crude oils allows differentiation of the more plausible and implausible oil charge histories for that particular reservoir. Clearly considerable refinement of this approach is needed but it appears that such a procedure has the potential, if developed further, to be a useful addition to the arsenal of petroleum geochemists and basin modelers. Knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, enables the estimation of missing charge in the basin, allows the detection of complex multi-history charge scenarios, and provides a much more robust and complete data set for calibration of basin model charge history assessments. It also, with further development may be integrated into stochastic basin modelling approaches to study petroleum systems.

Differential Thermal Evolution between Oil and Source Rocks in the Carboniferous Shale Reservoir of the Qaidam Basin, NW China

Shale oil and source rock samples of the Carboniferous Keluke Formation from well Chaiye 2 in the Delingha Depression were analyzed by gas chromatography–mass spectrometry. Source rocks were highly mature at the gas generation stage with vitrinite reflectance (Ro) of 1.45–1.88%. However, the oil produced from the shale reservoir was characterized by abundant biomarkers but low abundance of diamondoid hydrocarbons with estimated Ro of ca. 0.78%, indicating hydrocarbons were still at a relatively low thermal maturity level. As the crude oil was generated and accumulated autochthonously, preliminary results indicate that crude oil and source rocks witnessed differential thermal evolution and significant disparity of the current thermal maturity in the shale reservoir due to rapid tectonic subsidence and clay mineral catalysts that accelerated the thermal maturation process. Although tectonic uplifts occurred afterwards, the vitrinite recorded the highest maturity that source rocks have ever reached, whereas the oil has not reached the same maturity level due to less impact from thermal alteration or mineral catalysis than source rocks in the shale reservoir. Such a discovery enlarges the hydrocarbon perseveration of maturity ranges in reservoirs, particularly for the unconventional tight formation, and benefits potential hydrocarbon exploration from highly mature sediments.

Effects of evaporative fractionation on diamondoid hydrocarbons in condensates from the Xihu Sag, East China Sea Shelf Basin

Evaporative fractionation is a complex phenomenon associated with the separation of gas from oil in the subsurface, generally involving migration fractionation and gas invasion. The concentrations and distributions of diamondoid hydrocarbons in condensate samples with different type and extent of evaporative fractionation from the Xihu Sag, East China Sea Shelf Basin were investigated to determine the effects of evaporative fractionation on diamondoid hydrocarbons. The results suggest that both migration fractionation and gas invasion can affect the concentrations and distributions of diamondoid hydrocarbons. Residual oils after migration fractionation are generally characterized by relatively high concentrations of diamondoid hydrocarbons and low methyladamantanes/methyldiamantanes (MAs/MDs) ratios. However, maturity parameters based on diamondoid hydrocarbon isomers do not vary significantly from other typical maturity parameters, suggesting that they can still be used to assess maturity. Gas invasion causes the concentrations of diamondoid hydrocarbons in oil samples to rise generally, along with methyladamantanes/methyldiamantanes (MAs/MDs) and adamantane/diamantane (A/D) ratios, indicating that the effects of gas invasion on diamondoid hydrocarbons in oils are different from those of migration fractionation. In addition, gas invasion causes some changes in the diamondoid derived maturity parameters. Thus, the effects of gas invasion should be considered when using diamondoid hydrocarbons to evaluate the thermal maturity of crude oil. Diamondoid hydrocarbon concentrations and distributions in petroleum can be affected by evaporative fractionation, suggesting that it is possible to determine evaporative fractionation according to the diamondoid hydrocarbon composition. It can be proposed that the decreasing values of MAs/MDs ratios and increase of diamondoid concentration are indicators of migration fractionation, and increasing values of A/D, MAs/MDs and diamondoid concentration might suggest the introduction of additional gas.

Quantitative diamondoid analysis indicates oil cosourcing from a deep petroleum system onshore Niger Delta Basin

The Niger Delta Basin is one of the most prolific hydrocarbon provinces in the world, yet the origin of the vast amounts of oil and gas found in the numerous sub-basins across the delta remains contested. A total of 180 oil samples from more than 40 oil fields in the Niger Delta were analyzed by gas chromatography (GC), GC-mass spectrometry (GC-MS) and selected samples by GC-tandem mass spectrometry (GC-MSMS). The interpreted thermal maturity and source depositional environments of these hydrocarbons show significant variation depending on the components analyzed, and allow no clear correlation to a single source rock but rather imply extensive mixed contributions. Diamondoid hydrocarbon parameters were used for the first time on these Paleogene–Neogene reservoired oils to investigate source, thermal maturity and mixing effects and to perform cross-correlations of these oils. The diamondoid abundances and distributions support the hypothesis of co-sourcing of oil from a thermally cracked, sub-delta, Type II marine source, which was then mixed with oils of relatively lower maturities in the Paleogene–Neogene reservoirs. Future geochemical interpretations should treat the Niger Delta oils as potential mixtures of oils of variable maturities from different sources, often with the most important source biomarkers depleted because of the extent of thermal cracking.

Origin of deep oil accumulations in carbonate reservoirs within the north Tarim Basin: Insights from molecular and isotopic compositions

Large amounts of light oil have been produced from carbonate reservoirs at depths below 7 km in the recently discovered Shunbei and Yuecan oil fields within the north Tarim Basin. Eighteen samples were investigated for molecular and isotopic compositions to help understand the origin of these deep oil accumulations. Several ratios based on C6 and C7 hydrocarbons suggest that they were not affected by evaporative fractionation. Linear relationships between the carbon number and log of the mole fraction of n-alkanes support no fractionation alteration. The correlation between concentrations of methyldiamantanes and stigmastane indicates that these oils were not severely cracked and probably at the beginning or an early stage of intense oil cracking. C29 sterane isomerization ratios 20S/(20S + 20R) and ββ/(ββ + αα) have reached their equilibrium points while a good linear relationship between the concentrations of terpanes and steranes suggests variations in maturity. Calculated vitrinite reflectance of source rocks based on phenanthrene and diamondoid hydrocarbons shows different ranges, which may reflect multiple oil charges to these deep oil accumulations. A narrow range of δ13C values of whole oil and oil fractions suggest a genetic correlation of these oils. Triangular plots based on C6 and C7 hydrocarbons and diamantanes also indicate a very similar source. In addition, several ratios based on n-alkanes, isoprenoids, tri-, tetra-, and pentacyclic saturated hydrocarbons support a common source. However, oil SB7 seems to differ from the others in terms of source rock depositional environment, indicated by its much higher pristane/phytane ratio and lower dibenzothiophene/phenanthrene ratio as well as a much lower dibenzothiophenes concentration.

The dating of petroleum fluid residence time in subsurface reservoirs. Part 1: A radiolysis-based geochemical toolbox

The radiometric dating of geological events was a crucial achievement leading to the establishment of the geological time scale. The dating of the timing of petroleum charge into, and the determination of petroleum residence times in a geological trap would also be significant, as it would remove ubiquitous speculation concerning the history of reservoir charging in any basin setting. A thorough review of prior strategies to estimate the residence time of petroleum fluids in subsurface reservoirs revealed that few if any methods currently used provide useful estimates of the residence age of fluids. This paper is focused on the age dating of petroleum residence time in reservoirs based on the compositional alterations of reservoired fluids caused by natural radiation. This preliminary paper sets out the geochemical landscape and constraints on radiation-based age dating proxies. We report results on the propagation of radiation through reservoir rocks, which indicate that gamma radiolysis is a primary route to crude oil alteration. Gamma ray radiolysis experiments on crude oils at both natural and elevated radiation doses have been completed and the changing crude oil composition observed using LC, GC-MS and NMR. Reservoir fluids are naturally immersed in radioactive subsurface media that cause systematic alteration to crude oil composition with time, but the chemical changes are small in most natural settings. The degree of radiolysis of individual petroleum compounds was found to depend on chemical class, molecular size, initial compound concentration and the nature of the oil matrix, indicating that a proxy system for dating of petroleum charge times and oil residence times in petroleum traps will likely depend on case-specific calibrations. We define the apparent gamma ray radiolysis susceptibility (kGy−1) of different compounds. Large alkanes, such as high molecular weight normal alkanes (>C22) or hopanes, have high radiolysis susceptibility and show the most rapid decrease in component concentration with increasing radiation dose. In contrast, condensed aromatic hydrocarbons and diamondoid hydrocarbons are more resistant to decomposition through radiolysis. While assessing the decrease in concentration of a compound through radiolysis is a practical objective, it is more difficult to assess the production of new, unique radiolysis products given the great diversity and low concentrations of individual compounds produced. However, monitoring the production of specific functional groups during radiolysis of crude oils, using NMR spectroscopy, was found to be a feasible proxy analytical target. Analysis of newly generated carbon-carbon double bonds in bulk crude oils may represent an optimal approach for development as a radiolysis proxy. We propose a route to assessing in-reservoir crude oil radiation dose.

An examination by GC×GC-TOFMS of organic molecules present in highly degraded oils emerging from Caribbean terrestrial seeps of Cretaceous age

For our ancestors, oil seeps were both a fascination and a resource but as the planet's reserves of high quality low density oil becomes increasingly depleted, so there is now a renewed interest in heavier, biodegraded oils such as those encountered in terrestrial seeps. One such seep is Pitch Lake in the Caribbean island of Trinidad, which is the largest natural deposit of asphalt in the world. At the northern end of the Caribbean, oil emerges along a tectonic contact on the island on Cuba. The sources of the oils from these seeps are relatively recent and both are subject to intense weathering due to the tropical conditions. When analysed by gas chromatography (GC) both oils appear as unresolved complex mixtures (UCM) and show a very high degree of biodegradation thus presenting an analytical challenge. In this case study, these two Caribbean seep oils were analysed by comprehensive two dimensional GC with time of flight mass spectrometry (GC×GC-TOFMS) to expose many thousands of the individual compounds that comprise the UCM. The high chromatographic resolution of the GC×GC-TOFMS produced good quality mass spectra allowing many compounds including molecular fossil ‘biomarkers’ to be identified. Compound classes included diamondoid hydrocarbons, demethylated hopanes and seco-hopanes, mono- and tri-aromatic steroids. D-ring aromatised structures of the 8,14-seco-hopanes, including demethylated forms were present in both oils but further demethylation, probably at position C-25 during biodegradation, was only observed in the Pitch Lake oil. Many polycyclic aromatic hydrocarbons (PAHs) were absent although the fungal-derived pentacyclic PAH perylene was present in both oils. The presence of the angiosperm biomarker lupane in the Pitch Lake oil constrained the age to the Late Cretaceous. The higher degree of biodegradation observed in the Cuban oil was likely due to relatively slow anaerobic processes whereas oil within Pitch Lake was probably subject to additional more rapid aerobic metabolism within the lake.

Hydrocarbon biomarkers and diamondoid hydrocarbons from late Precambrian and lower Cambrian rocks of the Katanga saddle (Siberian Platform)

This study presents geochemical data on organic-rich rock samples collected from Riphean—Lower Paleozoic strata (potential source rocks) of the southern Siberian Platform and compositional data on hydrocarbon biomarkers (steranes, terpanes, n-alkanes, 12- and 13-methylalkanes, isoprenanes) and diamondoid hyrocarbons from core samples collected from the Kulindinskaya-1 well, which was drilled by RN-Exploration in 2012 within the Katanga saddle.

COMPOSITION OF DIAMONDOIDS IN OIL SAMPLES FROM THE ALPINE FORELAND BASIN, AUSTRIA: POTENTIAL AS INDICES OF SOURCE ROCK FACIES, MATURITY AND BIODEGRADATION

Twenty‐seven oil samples from Cretaceous, Eocene and Rupelian reservoir rocks in the Alpine Foreland Basin (Austria) were analysed to evaluate the composition of diamondoid hydrocarbons using gas chromatography – triple quadrupole mass spectrometry. The oils were generated from marly and shaly Oligocene source rocks buried beneath the nappes of the Alpine foldbelt to the south of the study area. Diamondoid hydrocarbons were detected in the saturated fraction of all the analysed oils. A biodegraded oil sample from a shallow reservoir in the NE part of the study area showed an enrichment in diamondoids due to the molecule's high resistance to microbial degradation. Variations in the organic matter type of the source rock facies and differences in maturity are known to influence the composition of diamondoids. However in this study, biomarker‐derived maturity parameters do not show a convincing correlation with diamondoid maturity parameters. Moreover, no cracking trend based on biomarkers and diamondoid concentrations was observed. The results indicate that the composition of diamondoids in oils from the Austrian part of the Alpine Foreland Basin is mainly controlled by heterogeneities in the Lower Oligocene source rocks, including the occurrence of a redeposited source rock succession in the western part of the study area. By contrast, EAI‐1 (the ethyladamantane index) shows a good correlation with various maturity parameters and seems to be independent of source rock facies.

Origins of Jurassic oil reserves in the Turpan–Hami Basin, northwest China: Evidence of admixture from source and thermal maturity

Middle–Lower Jurassic coaly shales were considered to be the source of Jurassic oil reserves in the Turpan–Hami Basin. In this study, we investigated the molecular and stable isotopic compositions of 35 gas samples and the geochemical parameters for 28 oil samples to reexamine the origin of these hydrocarbons. We show that the Jurassic natural gas reserves are derived mainly from coaly source rocks in the Middle Jurassic Xishanyao and Lower Jurassic Badaowan formations with maturities varying from 0.6% to 0.9%Ro. However, analysis of the low molecular weight hydrocarbons and diamondoid hydrocarbons shows that the maturities of the oils are clearly higher than those of the Jurassic coal measures and the natural gas generated from them. Their molecular and carbon isotopic compositions indicate that most of the Jurassic oil reserves are derived from pre-Jurassic lacustrine mudstones. The Hongtai gas/condensate field is an exception where the Jurassic coal measures are major contributors of light hydrocarbons. In contrast, the biomarker fingerprints of the Jurassic oils reveal a predominantly humic origin, which is most probably resulted from migration contamination. As such, the Jurassic petroleum system of the Turpan–Hami Basin is a mixed oil system derived from pre-Jurassic lacustrine mudstones and the Middle–Lower Jurassic coaly source rocks. This study opens pre-Jurassic structures in the Turpan–Hami Basin as favorable exploration prospects and illustrates the value of multiple correlation techniques to determine the sources of associated light and heavy hydrocarbons.

NMR spectral properties of the tetramantanes - nanometer-sized diamondoids.

Tetramantanes, and all diamondoid hydrocarbons, possess carbon frameworks that are superimposable upon the cubic diamond lattice. This characteristic is invaluable in assigning their (1)H and (13)C NMR spectra because it translates into repeating structural features, such as diamond-cage isobutyl moieties with distinctively complex methine to methylene signatures in COSY and HMBC data, connected to variable, but systematic linkages of methine and quaternary carbons. In all tetramantane C22H28 isomers, diamond-lattice structures result in long-range (4)JHH, W-coupling in COSY data, except where negated by symmetry; there are two highly symmetrical and one chiral tetramantane (showing seven (4)JHH). Isobutyl-cage methines of lower diamondoids and tetramantanes are the most shielded resonances in their (13)C spectra (<29.5 ppm). The isobutyl methylenes are bonded to additional methines and at least one quaternary carbon in the tetramantanes. W-couplings between these methines and methylenes clarify spin-network interconnections and detailed surface hydrogen stereochemistry. Vicinal couplings of the isobutyl methylenes reveal positions of the quaternary carbons: HMBC data then tie the more remote spin systems together. Diamondoid (13) C NMR chemical shifts are largely determined by α and β effects, however γ-shielding effects are important in [123]tetramantane. (1)H NMR chemical shifts generally correlate with numbers of 1,3-diaxial H-H interactions. Tight van der Waals contacts within [123]tetramantane's molecular groove, however, form improper hydrogen bonds, deshielding hydrogen nuclei inside the groove, while shielding those outside, indicated by Δδ of 1.47 ppm for geminal hydrogens bonded to C-3,21. These findings should be valuable in future NMR studies of diamondoids/nanodiamonds of increasing size.

Geochemistry, origin and accumulation of continental condensate in the ultra-deep-buried Cretaceous sandstone reservoir, Kuqa Depression, Tarim Basin, China

A continental condensate field, with the deepest burial depth (7084 m) so far in China, was recently discovered from the Cretaceous sandstone reservoir in the Bozi area of the Kuqa Depression, Tarim Basin. In this paper, we report general features of this field, including geochemistry of the condensates, their origin, and migration and accumulation. General geochemistry of the condensate reflects that it is an over pressured condensate reservoir. Analytical results by newly-developed high-resolution GC × GC–TOFMS method indicate that the condensate is rich in n-alkanes from nC3 to nC34 and in diamondoid hydrocarbons with a high content of adamantanes. The condensate has a high abundance of aromatic hydrocarbons. The gas δ13C2 values in these are −23.3‰, which is characteristic of coal-derived gases. Compared with the contents of conventional condensate oils, the BZ1 well has a high content of aromatic hydrocarbons, suggesting that the condensate is in a stage of highly mature cracking. Analyses of oil biomarkers, carbon isotopes, gas compositions, etc., revealed that the condensate is dominantly sourced from the highly mature coals of the Jurassic Qiakemake Formation in the western Kuqa Depression. This set of coal source sequences has generated large quantities of condensate since 3 Ma, when the study area was subjected to a rapid subsidence with sediments over 2000 m and consequently attained at the condensate-generating stage. Such condensates then migrated vertically into the Cretaceous traps along faults. Therefore, the Bozi condensate field is a typical case of large-scale oil/gas field characterized by late-stage accumulation. Multiple elements favor the formation of this large-scale condensate field. The timing of trap formation accords with that of the condensate generation (since 3 Ma). The traps and source rocks are stacked vertically. Faults connect the source rock sequences and the reservoirs. The hydrocarbon charge is strong and efficient. Thick Paleogene gypsum beds act as an excellent cap rock, favoring the accumulation and preservation of the condensate.

IN‐RESERVOIR FRACTIONATION AND THE ACCUMULATION OF OIL AND CONDENSATES IN THE SURMA BASIN, NE BANGLADESH

Petroleum in the Surma basin, NE Bangladesh (part of the Bengal Basin) ranges from waxy crude oils to condensates. The origin and source rocks of these hydrocarbons were investigated based on the distributions of saturated and aromatic hydrocarbons in 20 oil samples from seven oil and gas fields. The relative compositions of pristane, phytane and adjacent n‐alkanes suggest that the source rock was deposited in a non‐marine setting. The abundance and similar distribution of biphenyls, cadalene and bicadinanes in most of the crude oils and condensates indicates a significant supply of higher‐plant derived organic matter to the source rocks. Maturity levels of the crude oils and condensates from the Surma basin correspond to calculated vitrinite reflectance (Rc) values of 1.0–1.3%, indicating hydrocarbon expulsion from the source rock at a comparatively high maturity level. The Rc values of oils from the Titas field in the southern margin of the Surma basin are relatively low (0.8–1.0%). Some oils were severely biodegraded. The similar distribution of diamondoid hydrocarbons in both biodegraded and non‐biodegraded oils indicated similar types of source rocks and similar maturity levels to those of oils from the Surma basin. The Oligocene Jenam Shale and/or underlying non‐marine deposits located at greater depths may be potential source rocks. The diversity of the petroleum in the Surma basin was likely due to evaporative fractionation, resulting in residual waxy oils and lighter condensates which subsequently underwent tertiary migration and re‐accumulation. Evaporative fractionation due to modification of the reservoir structure occurred during and after the Pliocene, when large‐scale tectonic deformation occurred in and around the Bengal Basin.

Diamondoid Hydrocarbons as Maturity Indicators for Condensates from Southern Indus Basin, Pakistan

Diamondoid hydrocarbons have been examined in condensates reservoired in the Southern Indus Basin using GC‐MS. Bulk properties reveal that samples are waxy and low sulfur with the exception of Pakhro and Gopang which are nonwaxy. TIC show bimodal distribution of n‐alkanes along with high abundance of C20+ n‐alkanes indicating substantial contribution of terrigeneous OM in these samples. CPI close to one is consistent with mature nature of oils. The samples show two ranges of Pr/Ph ratios. Those within the range of 2.2–2.7 reflect marine depositional settings for OM while others with Pr/Ph &gt;3 may have originated from terrestrial OM deposited under marine oxic conditions. The cross plot of Pr/n‐C17 versus Ph/n‐C18 indicate type III kerogen as main source of OM deposited under marine to marine oxic conditions. The values of diamondoid based maturity parameters, like methyladamantane index 54.1–75.8% and methyldiamantane index 34.9–56.3% indicate high level of thermal maturity corresponding to vitrinite reflectance 1.1–1.6%. No biodegradation is observed in any of these samples as shown by methyladamantanes/adamantane 3.99–5.52 and methyldiamantanes/diamantane 2.16–2.99 and supported by high values of API gravity (45.13°–60.02°) and absence of UCM.

Palaeo-fluid evidence of the multi-stage hydrocarbon charges in Kela-2 gas field, Kuqa foreland basin, Tarim Basin

Abstract The multi-stage hydrocarbon charge process of Kela-2 gas field in the Kuqa foreland basin was studied from the perspective of palaeo-fluid evidence by the analyses of fluid inclusions, fluorescence spectroscopy, FE-SEM (field emission scanning electron microscopy) observation, core micro-CT scanning, and hydrocarbon geochemistry. The result shows that the Kela-2 gas field has experienced three periods of hydrocarbon charge process: (1) charged with oil at the early-middle period of the Miocence (N 1 ), (2) charged with high maturity oil & gas at the sedimentary period of the Pliocence Kuqa Formation (N 2 ) and then destroyed by intense tectonic compression, and (3) charged with high- and over-maturity coal-derived gas since the Quaternary. The widely distributed residual dry bitumen, the occurrence of gas-liquid two-phase hydrocarbon inclusions, the residual oils observed in the nanopores, the higher QGF and QGF-E index, and the higher S 1 , S 2 values of rock pyrolysis detected in both current gas zone and water zone, are the evidence of early oil charges. The residual dry bitumen, the occurrence of gas-oil-solid (bitumen) three-phase hydrocarbon inclusions, the loss of light n-alkanes and the relatively high content of aromatic hydrocarbons in the condense oil, and the abnormally high content of diamondoid hydrocarbons, are the strong evidence of gas flushing and deasphalting.

Diamondoids: occurrence in fossil fuels, applications in petroleum exploration and fouling in petroleum production. A review paper

In this review paper, we report the molecular structure, origin, natural occurrence and variety of diamondoid hydrocarbons in petroleum fluids and other fossil fuels. In addition, we present the role of diamondoids as geochemical tools for petroleum characterisation, ways diamondoid molecules are used to play an important role in petroleum evaluation, and may be used to assess origin, extend of biodegradation and thermal maturity, as well as to identify the occurrence of petroleum. The diamondoid-based diagnostic ratios in environment science as well as diamondoid-based diagnostic ratios for petroleum maturity parameters are also presented and discussed. Such diamondoid-based parameters may be used to assess oil source, maturity and biodegradability, providing supporting information, especially when traditional evaluation data are not available or are difficult to interpret. We also report applications and problems associated with diamondoids in petroleum exploration and production. That is the role of diamondoids in petroleum and natural gas production fouling as well as separation, detection and measurements of petroleum diamondoids. We realise that the presence of diamondoids in petroleum has become much more than a chemical curiosity since it has advanced to be a resourceful instrument in petroleum science, biomedicine, materials science and an important family of molecular building blocks in nanotechnology. (Received: August 9, 2011; Accepted: November 23, 2011)

Generation of diamondoid hydrocarbons as confined compounds in SAPO-34 catalyst in the conversion of methanol

Formation of adamantane hydrocarbons and their confinement in SAPO-34 caused the long induction period and the quick catalyst deactivation in methanol conversion. Via ship-in-a-bottle synthesis, adamantane and methyladamantanes could be produced from methanol conversion in the cage of 8-ring SAPO catalysts under very mild reaction conditions.

Thiadiamondoids as proxies for the extent of thermochemical sulfate reduction

Thiadiamondoids have been analyzed in a suite of Smackover-derived oils from the US Gulf Coast to determine whether their abundance and distribution reflect alteration by thermochemical sulfate reduction (TSR). The sample suite includes oils and condensates having various thermal maturities that are characterized as being unaltered by TSR, altered by TSR, or of uncertain affinities due to inconsistencies between conventional geochemical indicators of TSR. Nearly all samples contain thiadiamondoids, indicating that small amounts of these compounds can be generated from sulfur rich kerogen. TSR results in the generation of H2S, sulfides and thiophenic aromatic hydrocarbons, either by reaction with sulfate or by back reactions with the evolved H2S. Evidence shows that thiadiamondoids originate exclusively from reactions involving TSR. Once generated, their high thermal stability permits thiadiamondoids to accumulate with little further reaction and their abundance reflects not only the occurrence of TSR, but the extent of the alteration. The abundance of thiaadamantanes (1-cage structures) is particularly diagnostic of the onset of TSR. Examination of condensates from reservoirs >180°C indicates that the thiadiamondoids can be thermally degraded. They are more thermally stable than the dibenzothiophenes, but are less stable than diamondoid hydrocarbons. Their stability appears to increase with increasing cage number, suggesting that the thiatriamantanes are the best proxy for the extent of TSR alteration in very high temperature reservoirs. Polythiadiamondoids (diamondoids with multiple sulfur substitutions) were detected in trace amounts and are also indicators of TSR.

Identification of individual tetra‐ and pentacyclic naphthenic acids in oil sands process water by comprehensive two‐dimensional gas chromatography/mass spectrometry

The oils sands industry of Canada produces large volumes of process water (OSPW) which is stored in large lagoons. The OSPW contains complex mixtures of somewhat toxic, water-soluble, acid-extractable organic matter sometimes called 'naphthenic acids' (NA). Concerns have been raised over the possible environmental impacts of leakage of OSPW and a need has therefore arisen for better characterisation of the NA. Recently, we reported the first identification of numerous individual tricyclic NA in OSPW by comprehensive two-dimensional gas chromatography/time-of-flight mass spectrometry (GCxGC/ToF-MS) of the methyl esters. The acids were diamondoid adamantane acids, resulting, it was proposed, from biotransformation of the corresponding alkyladamantane hydrocarbons, which is a known process. Biotransformation of higher alkylated diamondoid hydrocarbons was, until now, unknown but here we describe the identification of numerous pentacyclic NA as diamantane and alkyldiamantane acids, using the same methods. Further, we suggest tentative structures for some of the tetracyclic acids formed, we propose, by ring-opening of alkyldiamantanes. We suggest that this is further evidence that some of the acid-extractable organic matter in the OSPW originates from extensive biodegradation of the oil, whether in-reservoir or environmental, although other oxidative routes (e.g. processing) may also be possible. The results may be important for helping to better focus reclamation and remediation strategies for NA and for facilitating the identification of the sources of NA in contaminated environmental samples.