Terpane Biomarkers Research Articles

Maturation changes of hydrocarbons in solid parts of peloids from Serbian spas - catalytic influence of clay minerals

The study focused on inspecting the composition of n-alkane, sterane and terpane biomarkers in healing mud (peloid) organic matter in the Rusanda, Bujanovac and Vranje spas. It was assumed that the catalytic influence of minerals on changes in biomarkers could be effectively evaluated based on the distribution of their biolipid and thermodynamically more stable geolipid structural and stereochemical isomers. Quartz, illite, kaolinite, plagioclase, smectite and chlorite were identified in the samples by powder X-ray diffraction. n-?lkanes, terpanes and steranes were analyzed in the solid parts of the peloids using the gas chromatography-mass spectrometric, GC-MS, technique. In Rusanda and Bujanovac samples, n-alkanes were identified with distributions characteristic of immature sediments. In contrast, distributions of terpanes and steranes are typical for the mature organic matter of old sedimentary formations. It was concluded that the identified clay minerals do not have an obvious catalytic effect on the maturation of n-alkanes. At the same time, the presence of illite, chlorite, and smectite compensated for all other missing factors (heat, pressure and geological time) by catalytic action and, as a result, gave terpanes and steranes with distributions that are characteristic for petroleum, as the most mature form of organic matter in the geosphere.

Geochemical evaluation of produced petroleum from the Middle Permian Lucaogou reservoirs Junggar Basin and its implication for the unconventional shale oil play

The shale of the Middle Permian Lucaogou Formation in the Jimusaer Sag has become one of the most important prospects for unconventional shale oil production in China. The Lucaogou Formation develops two sweet spots, the upper (P2l22) and lower (P2l12) sweet spots, which are not more than 150 m apart. Interestingly, oils produced from the lower sweet spots have higher densities and viscosities than those in the upper sweet spots. Meanwhile, these high-viscosity oils have brought technical challenges to shale oil production. In this paper, geochemical data from 78 source rock solvent extracts and 17 oil samples from various depths were employed to elucidate unconventional petroleum systems and the reason for high viscosities. The source rocks of the Lucaogou Formation are good to excellent, primarily type II and II-III kerogens, and are now in the early-peak oil window. Oils produced from the P2l12 interval are characterized by abundant polar compounds, which are derived from the P2l12 and P2l11 intervals source rocks with relatively high marine sources contribution. Oils in the P2l22 interval are generated from the P2l22 interval source rocks with relatively high terrigenous-marine sources contribution. Terpane biomarker ratios indicate all oil samples are derived from lacustrine source rocks. The distributions of terpanes and steranes in these samples are similar, with high quantities of C29 steranes and low amounts of diasteranes. Migration from sources to reservoirs in the Lucaogou shale oil systems is short-distance given thermal maturity considerations. All oil samples have experienced slight biodegradation (PM level 1–2) at most. The sources and thermal maturities are the primary reasons for the high viscosities of the crude oils produced from the P2l12 interval. This research also indicates the Lucaogou shale petroleum system could be divided into two subsystems, and the production of different unconventional petroleum subsystems requires different strategies.

Evolution characteristics of maturity-related sterane and terpane biomarker parameters during hydrothermal experiments in a semi-open system under geological constraint

In order to accurately assess the thermal maturity of highly/over-mature shales in Paleozoic strata in southern China, hydrothermal experiments of shale samples from the Dalong Formation from bed 18 of well-exposed Shangsi PTB Section was conducted in a semi-open system under various conditions of geological constraint. The saturated extracts of pyrolyzed shale samples were subjected to gas chromatography and mass spectrometry (GC-MS) analyses. The results indicated that hydrothermal experiments of Dalong shales in the presence of fluid pressure (FP), lithostatic stress (LS), water, catalyst of clay minerals and trace elements, is partially equivalent to catalytic hydropyrolysis in terms of the catalytic hydrogen effect for the release of bound biomarkers from geomacromolecules of kerogen and asphaltene. The evolutional trend of maturity-related biomarkers were classified into the following three categories: (a) the most common maturity parameters (e.g., Ts/(Ts + Tm) and C29S/(S + R)) initially increased and then decreased with a pyrolysis temperature (450 °C) at the reversal point during maturation; (b) the parameters (e.g., C32S/(S + R)) primarily increased or decreased and reached a temperature (400 °C) of tuning point, and then remained unaltered with increasing temperature (c) the parameters (e.g., C27DS/S); firstly increased, and then declined at a specific turning point temperature (425–500 °C), and thereafter continued to increase until the end of heating process. As a result, the threshold temperature for the release of bound sterane or terpane occurred in the range 400–500 °C. Most maturity-related sterane and terpane biomarker parameters cannot be applied to evaluate the maturity of highly/over-mature shale. However, the C30M/C30H ratio and S/T ratio, which are strongly correlated with temperature, may be employed to assess extremely mature shale from these Paleozoic strata due to the integrated effects of multiple factors in the thermal evolution process of biomarkers. This is very important for the exploration and development of shale gas in southern China. Additionally, the values of several source-related biomarker parameters derived from C27–29 regular steranes are relatively constant during maturation, such as the ternary plot of the C27–29 αααR sterane versus the C27/C29 αααR sterane ratio. These are useful indicators for distinguishing the genetic source of highly/over-mature shales.

Characterization of the import of Botryococcus to the source rocks of the upper member of the Lower Ganchaigou Formation in the Yingxi area, Qaidam basin, China

Substantial quantities of Botryococcus fossils have been detected in the source rocks of the upper member of the Lower Ganchaigou Formation in the Yingxi area, Qaidam basin, China. Dicyclic terpane biomarkers, predominantly drimanes or homodrimanes with the same characteristics, also have been detected in extracts from the source rocks. These salient features confirm that Botryococcus is an important parent material for the high-quality source rocks of the upper member of the Lower Ganchaigou Formation of the western Qaidam basin. Our findings contribute to a better understanding on this source rock series and its mechanisms of hydrocarbon generation.

Paleoenvironmental significance of biomarker and stable isotope (2H, 13C, 15N, 18O, and 34S) investigations on a Pliocene coal-bearing sequence (Denizli Basin, southwestern Turkey)

Pliocene coal, clayey coal, and coaly claystone sediments from the Yatağan Formation (Denizli Basin, southwestern Turkey) have been investigated with respect to maceral association, mineralogical composition, n-alkane, isoprenoid and saturated-aromatic biomarker characteristics, and stable isotopes (2H, 13C, 15N, 18O, and 34S). The main purpose of the present study was to determine the hydrocarbon potential and paleodepositional conditions of coals in the Denizli Basin. The abundances of huminite, liptinite, and inertinite macerals were 46.14%, 8.06%, and 1.57%, respectively. The huminite/vitrinite reflectances (%Ro) of the coal, clayey coal, and coaly claystone samples ranged between 0.26 and 0.37 %Ro, implying sub-bituminous B and C coal ranks. The total organic C (TOC, wt.%) content and the Tmax values of the investigated samples ranged between 0.74 and 43.80 wt% and 390–440 °C, respectively. In addition, the coaly horizons were characterized by very low H index (HI), O index (OI), production index (PI), and Tmax values. Moreover, a high waxiness degree, C preference index (CPI), odd-to-even predominance (OEP), terrigenous/aquatic ratio (TAR), and high C19 tricyclic terpane/C23 tricyclic terpane (C19/C23 TT) and C24 tetracyclic terpane/C26 tricyclic terpane (C24*/C26 TT) biomarker ratios indicated a terrestrial plant input. These results were supported by stable isotope (2H, 13C, and 15N) investigations. Although the Pliocene coals have source rock potential according to the TOC content and pyrolysis analyses, they have been determined to be at the diagenesis and immature stages as a result of organic petrographic, and saturated-aromatic biomarker investigations.

Genesis and evaporative fractionation of subsalt condensate in the northeastern margin of the Amu Darya Basin

This paper studied the origin and the maturity of the Jurassic subsalt condensate in the northeastern margin of the Amu Darya Basin and analyzed its formation condition and mechanism through conducting geochemical analysis of biomarkers, carbon isotopes and light hydrocarbons of condensate and source rock. Combining geology and geochemistry analysis, this paper compared the components of natural gas and associated condensate, and conducted oil-source correlation as well as analyzed condensate maturity in nine gas reservoirs. The genesis and geological conditions of condensate in the northeastern margin of the Amu Darya Basin were analyzed and a geological model of condensate accumulation was thereby established. The results show that natural gas in the northeastern margin of the Amu Darya Basin is dry gas with residual oil and oil intrusion. Parameters, e.g., saturated hydrocarbon distribution, sterane and terpane biomarkers and isotopes, suggest that the condensate was primarily derived from the Upper Jurassic marine source rocks. Mature condensate was identified using maturity parameters, e.g., heptane and isoheptane, light hydrocarbons 2,4-DMP/2,3-DMP(Dimethyl Pentane), C29sterane isomerization and aromatic hydrocarbon methylphenanthrene index. The relationship between light hydrocarbon paraffinicity and aromaticity indicates that the condensate was derived from evaporative fractionation. Comprehensive analysis draws the conclusion that condensate at subsalt reservoir in the northeastern margin of the Amu Darya Basin was contributed by evaporative fractionation. Oil generated by the Upper Jurassic marine source rocks at early stage was concentrated in the subsalt carbonate strata. Considerable dry gas was generated by Middle and Lower Jurassic coal-bearing source rocks in the late stage migrated to the Upper Jurassic reservoirs and displaced crude oil due to the absence of interlayers. And the light hydrocarbons in the oil were dissolved in natural gas and therefore formed condensate. The evaporative fractionation under subsalt was contributed by: (1) two sets of source rocks, e.g., one is gas-prone and the other is oil-prone, (2) no obvious barriers between these source rocks, (3) excessive natural gas generated.

Characterization of organic-rich shales for petroleum exploration & exploitation: A review-Part 2: Geochemistry, thermal maturity, isotopes and biomarkers

As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ratio (C1/Σ(C2+C3)), and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production “sweet-spots”, discriminate oil-, gas-liquid- and gas-prone shales from kerogen compositions and thermal maturities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indicative of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance (Ro) measurements of thermal maturity highlight discrepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measurement, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, stable and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identification, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions associated with them.

Revealing minor terpane biomarkers in lubricants and soils using the customized cleanup method

Purpose Lubricant oils are popularly applied and the spill incidents are seen ubiquitously in the environment, in which the terpane biomarkers are the most abundant compounds and which are the essential compounds in the contaminated soils. We studied the traditional and modified cleanup protocols and developed a negative pressure cleanup device and proposed a more suitable internal standard in the quantitation of biomarkers, wherein the main terpane compounds in a lubricant and soil samples were identified.

Residual-Oil Zone: Paleo-Oil Characterization and Fundamental Analysis

Summary In most reservoirs around the world, paleo oil exists below the free-water level (FWL) and is considered residual oil to natural/geological waterflood. This nontrivial resource of residual oil will not flow by primary- or secondary-recovery means but requires carefully designed enhanced-oil-recovery (EOR) methods to mobilize it. To date, there is no detailed analysis of paleo oil in the literature simply because it is difficult to obtain a reservoir sample. This study provides a comprehensive paleo-oil analysis for samples obtained from reservoir sponge cores. The oil in the sponge core was extracted, analyzed, and compared with main-pay-zone (MPZ) oil. Critical data have been unveiled on paleo-oil characterization through fundamental studies on oil quality, fingerprint, filling history, available hydrocarbon components and compounds, and molecular-level characterization. It was found that the global composition and overall quality of paleo oil are very similar to those of the MPZ oil. However, the differences between the two oils were only apparent when the study was extended further to include molecular-level analysis and available hydrocarbon components and compounds. These differences may define the appropriate EOR methods to mobilize this oil and explain trapping mechanisms caused by fluid properties. Gas-chromatography (GC) studies revealed that paleo-oil extracts have the same pristane/phytane ratio as the MPZ oil, suggesting that they are of the same origins and share the same source rock. Further analysis showed a good match of the terpane biomarkers between paleo-oil extracts and MPZ oil but with slightly lower maturity levels. Paleo-oil quality was compared with MPZ oil by use of pyrolytic oil-productivity index (POPI) analysis which indicated the same °API range as the MPZ oil and the same light volatile, thermally distilled, and cracked components. Paleo and MPZ oils were also analyzed with low-field nuclear magnetic resonance (NMR) to qualitatively test the similarity of the oil components and to measure their apparent viscosities. Both oils have shown very comparable viscosity measurements and NMR signatures. The simulated distillation analysis showed that lighter components in paleo oil are less abundant than in MPZ oil, whereas medium-to-heavy components are relatively similar. A Fourier transform ion cyclotron resonance (FT-ICR) study, which zoomed into the heavier components, revealed that paleo oil has less aromaticity than MPZ oil and lacks aromatic sulfur and disulfur compounds, a negligible amount of nitrogen compounds, and no resin-type components. This study provides in-depth information about oil extracted from the residual-oil zone (ROZ), which does not flow by primary or secondary recovery means. To our knowledge, there is no available information in the literature that explains the components, compounds, quality, and behavior of this oil because it is difficult to obtain reservoir samples. These data shed light on a possible trapping mechanism caused by fluids in place. The study also used several methods and tools to confirm the conclusions and to ensure repeatability of results.

Occurrences and distributions of normal alkanes and biological markers to detections of origin, environments, and maturation of crude oils in El Hamed oilfield, Gulf of Suez, Egypt

ABSTRACTThe gas chromatography (GC) and gas chromatography–mass spectrometry (GC-MS) analyses for crude oils from Kareem reservoir in the wells El Hamed-1, 3, and 5 are used to provide information on source organic matters input, depositional environment, and maturation level. Data include normal alkane and acyclic isoprenoids distribution, terpane, and sterane aliphatic biomarkers. Pristine/phytane (Pr/Ph), Pr/nC17, and Ph/nC18 ratios indicated mixed organic sources of organic matters (kerogen type II, III) dominantly (kerogen type III) with a less effect of biodegradation and mature stage of occurrence. The diasteranes/steranes ratio showed generally low ratios as in most marine carbonate sources, while algal-bacterial organic matter contribution for the oil samples suggested dependence on the predominance of C23 tricyclic terpane relative to the C19 tricyclic terpane, and the C25 tricyclic terpane greater than C24 tricyclic terpane. The gammacerane index indicated that a low-salinity environment of deposition for the initial organic matters existed in the analyzed samples.

Origin and mixing of crude oils in Triassic reservoirs of Mahu slope area in Junggar Basin, NW China: Implication for control on oil distribution in basin having multiple source rocks

The origin of crude oils and their varied geochemical features along the western and northern slope of the Mahu depression in the Junggar Basin has been controversial. Based on the molecular and isotopic geochemistry of hydrocarbons from 46 drill-stem test crude oil samples and 36 core samples, three oil groups (I, II, III) and five subgroups (I1, I2, II, III1 and III2) have been recognized and oil-source correlations have been established. The subgroup I1 oils originated mainly from lower Permian Fengcheng (P1f) carbonate source rocks, subgroup I2 from P1f mudstone source rock and group II oils from Middle Permian Wuerhe (P2w) mudstone source rock whose potential was underestimated in the past. Group III consists of mixed oils, i.e., subgroup III1 received contributions from P1f carbonates and P2w mudstones and subgroup III2 is a mixture of oils from P1f mudstones and P2w-generated oils. In order to determine the main source rocks, the laboratory oil mixing experiments were carried out. Tricyclic terpane biomarker parameters (TTs) were used to quantify the source contributions. Whole oil carbon isotope ratios were also used to verify the proportions of different oils in each mixture. The results show that subgroup III1 oils have diverse mixing ratios in different reservoir, subgroup III2 oils are mainly from P1f mudstones and P2w source rock contributes little. Finally, the accumulation process of oil fields along the northern slope of the Mahu depression was analyzed and the contributions from different sources were revealed. This study provides an effective quantitative method to identify contributions from different lacustrine source rocks to mixed oils in the Mahu depression, which could be helpful in predicting location and composition of undiscovered oils.

Source Identification of Oil Spills Using Compound-Specific Carbon Isotope Analysis Based on “7–16” Oil Spill in Dalian, China

A set of sequentially weathered oils residue in sediments collected from Dalian Bay in different time after “7-16” oil spill accident, were analyzed by Gas chromatography–mass spectrometry (GC-MS) and Gas chromatography–isotope ratio mass spectrometry (GC-IRMS) to analyze the weathering process and evaluated the possibilities of GC-IRMS as a correlation tool in oil spill identification. Although some temporal variation was observed, no significant temporal shifts in the δ13C values for n-alkanes were measured in moderated weathered oils. The standard deviations of δ13C values of individual n-alkanes varied from 0.07% to 0.20%, which showed that the weathering has no significant effect on values of individual n-alkanes over 120 days. The results suggest that stable carbon isotope profile of n-alkanes can be a useful tool for tracing the source of an oil spill, particularly for the weathered oils absence of sterane and terpane biomarkers.

Geochemical evolution during the cracking of crude oil into gas under different pressure systems

Two comparative simulation experiments (a normal atmospheric-pressure opening system and a 20 MPa closed system) were conducted to study the geochemical evolution of n-alkane, sterane, and terpane biomarkers in the process of oil cracking into gas under different pressures. With an initial experimental temperature set at 300°C, the temperature was increased to 650°C at a heating rate of 30°C/h. The products were tested every 50°C starting at 300°C, and a pressure of 20 MPa was achieved using a water column. The low-maturity crude oil sample was from the Paleogene system in the Dongying sag in eastern China. The threshold temperature obtained for the primary oil cracking process in both pressure systems was 450°C. Before the oil was cracked into gas, some components, including macromolecular n-alkanes, were cracked into medium- or small-sized n-alkanes. The secondary oil cracking of heavy hydrocarbon gases of C2–5 to methane mainly occurred between 550°C to 650°C, and the parameters Ln(C1/C2) and Ln(C1/C3), as well as the dry coefficients, increased. Overpressure inhibited the oil cracking process. In the 20 MPa system, the oil conversion rate decreased, the temperature threshold for gas generation rose, and oil cracking was inhibited. Compared with the normal pressure system, high-carbon n-alkanes and other compounds in the 20 MPa pressure system were reserved. Furthermore, the parameters ΣC21−/Σ22+, Ln(C1/C2), and Ln(C1/C3), as well as the dry coefficients, decreased within the main temperature range. During secondary oil cracking (550°C to 600°C), the Ph/nC18 and Pr/nC17 decreased. High pressure influenced the evolution of the biomarkers Ts and Tm, C31 homohopane, C29 sterane, and their related maturity parameters to different extents during oil cracking under different temperature ranges.

Thermal maturity of northern Appalachian Basin Devonian shales: Insights from sterane and terpane biomarkers

To better estimate thermal maturity of Devonian shales in the northern Appalachian Basin, eleven samples of Marcellus and Huron Shale were characterized via multiple analytical techniques. Vitrinite reflectance, Rock–Eval pyrolysis, gas chromatography (GC) of whole rock extracts, and GC–mass spectrometry (GCMS) of extract saturate fractions were evaluated on three transects that lie across previously documented regional thermal maturity isolines. Results from vitrinite reflectance suggest that most samples are immature with respect to hydrocarbon generation. However, bulk geochemical data and sterane and terpane biomarker ratios from GCMS suggest that almost all samples are in the oil window. This observation is consistent with the presence of thermogenic gas in the study area and higher vitrinite reflectance values recorded from overlying Pennsylvanian coals. These results suggest that vitrinite reflectance is a poor predictor of thermal maturity in early mature areas of Devonian shale, perhaps because reported measurements often include determinations of solid bitumen reflectance. Vitrinite reflectance interpretations in areas of early mature Devonian shale should be supplanted by evaluation of thermal maturity information from biomarker ratios and bulk geochemical data.

Chemical Fingerprints of Alberta Oil Sands and Related Petroleum Products

Alberta oil sands are known to contain the world's largest reserves of bitumen. The rapid growth in their production could result in a significant environmental impact. Fingerprinting bitumen and petroleum products from the Alberta oil sands is essential in order to better understand the chemical compositions of oil sands, prepare for potential oil spills, and address the associated environmental problems. This study presents an integrated quantitative chemical characterization of Alberta oil sands bitumen and other related Alberta oils using gas chromatography-flame ionization detection (GC-FID) and gas chromatography-mass spectrometry (GC-MS). The characterized target hydrocarbons include n-alkanes, unsubstituted polycyclic aromatic hydrocarbons (PAHs) and their alkylated homologues (APAHs), biomarker terpanes and steranes, bicyclic sesquiterpanes, and diamondoids. The chemical features of bitumen in oil sands are clearly distinguishable from those of most other conventional crude oils. The chemical fingerprints of diluted oil sands bitumen and Albian Heavy Synthetic crude were significantly altered by either the diluent blended with the former or the upgrading processing of crude bitumen in the latter. A chromatographic hump of unresolved complex mixtures (UCMs) eluting between n-C10 to n-C40 is pronounced and n-alkanes are nearly absent in bitumen extracted from oil sands. Alkylated naphthalenes account for only a small proportion of the total APAHs in Alberta oil sands extracts. The PAH compounds in oil sands extracts and diluted bitumen are dominated by alkylated homologues with the relative distribution of C0– < C1– < C2– < C3– for all five APAH series. Biomarker terpanes and cage-like adamantanes were determined in almost identical abundance and distribution profile in oil sands extracts and diluted crude bitumen, while biomarker steranes and bicyclic sesquiterpanes were removed to varying degrees by physical weathering or biodegradation.

Fingerprinting Analysis and Characterization of Hydrocarbons in Sediment Cores from the Pearl River Estuary, China

The Pearl River Delta (PRD) in southern China has undergone rapid urbanization and industrialization over the past few decades, leading to a substantial accumulation of hazardous organic compounds and a significant environmental impact. Forensic analysis of estuarine sediments is critical in order to uncover the contamination history and evaluate the level of contamination of the aquatic system and its ambient regions. A number of hydrocarbons and hydrocarbon groups including polycyclic aromatic hydrocarbons (PAHs), biomarkers, and diamondoids were found in representative sediment cores collected in the Pearl River Estuary (PRE) with average values determined to be 1,300, 288, and 5.85 ng/g dry weight in core #1 (inner shelf) and 283, 26.8, and 2.06 ng/g dry weight in core #2 (outer shelf), respectively. The results clearly suggest that the contamination in PRE sediment was derived from various inputs including petrogenic, biogenic, and pyrogenic sources. Because diamondoids are naturally absent from modern sediments that are free from petroleum contamination, in addition to the signatures of determined alkylated PAHs and biomarker terpanes and steranes, the presence of trace diamondoid compounds provides further evidence of petroleum contamination in the offshore and coastal areas of the PRE.

Oil fingerprinting analysis using commercial solid phase extraction (SPE) cartridge and gas chromatography-mass spectrometry (GC-MS).

This study used solid phase extraction (SPE) cartridges for rapid cleanup and fractionation of oil samples in oil fingerprinting analysis. A series of commercially available florisil cartridges, normal phase SPE cartridges, and silica gel/cyanopropyl (SiO2/C3-CN) SPE cartridges was selected for the fractionation of oil into aliphatic and aromatic hydrocarbons. The florisil cartridges and normal phase SPE cartridges can clean up the oil samples but are unable to separate them into two fractions. The SiO2/C3-CN (1 g/0.5 g) SPE cartridge successfully separated oil samples into aliphatic and aromatic fractions by eluting with 4 mL of hexane and 4 mL of dichloromethylene (DCM)/hexane (3 : 1, v:v), respectively. No cross-elution was observed between aliphatic and aromatic fractions when oil loading mass was less than 40 mg on the SiO2/C3-CN SPE cartridge. The relative standard deviation (RSD) of five replicates of SPE-GC-MS analysis of 5 mg of reference oil is 2.8%, 1.2%, and 6.9% for total n-alkanes, polycyclic aromatic hydrocarbons (PAHs), and biomarkers, respectively. The recoveries of six spiked deuterated surrogates were all above 95%. This SPE-GC-MS method was used for the fingerprinting analysis of various crude oils, refined petroleum products, and environmental sediment samples. The characterized target hydrocarbons included n-alkanes, unsubstituted priority PAHs and alkylated homologues, and biomarker terpanes and steranes. The concentration profiles and diagnostic ratios of target compounds are both comparable to those obtained by the conventional silica gel column-GC-MS method.

Alkyl Naphthalenes and Phenanthrenes: Molecular Markers for Tracing Filling Pathways of Light Oil and Condensate Reservoirs

Abstract:Condensates and light oils are generally characterized by high maturity, low concentration of sterane and terpane biomarkers and low content of non‐hydrocarbon fraction. As a result, some commonly‐used sterane, terpane and carbazole migration parameters in conventional oil reservoirs may have a certain limitation in condensate and light oil reservoirs for their poor signal‐noise ratios in the gas chromatography‐mass spectrometry (GC‐MS). Naphthalene, phenanthrene and their methylated substituents, however, are present in significant concentrations in condensates and light oils. Taking the Fushan depression (in the Beibuwan Basin, Northern South China Sea) as an example, this paper attempts for the first time to use polycyclic aromatic hydrocarbon (PAH)‐related parameters to trace migration directions and filling pathways for condensate and light oil reservoirs. The result shows that TMNr (i.e. 1,3,7‐TMN/ (1,3,7‐TMN + 1,2,5‐TMN), TMN: trimethylnaphthalene)), MPI‐1 (i.e. 1.5×(2‐MP + 3‐MP)/(P + 1‐MP + 9‐MP), P: phenanthrene MP: methylphenanthrene), MN/DMN (σmethylnaphthalene/σdimethylnaphthalene, %) and MN/TMN (σmethylnaphthalene/σtrimethylnaphthalene, %) can be used to trace the filling pathways of condensate and light oil reservoirs. These parameters, together with geological consideration and other bulk oil properties (e.g. the gas to oil ratio and density), suggest that the condensates and light oils in the Huachang oil and gas field are mainly sourced from the Bailian sag that is located to the northeast of the Huachang uplift in the Fushan depression.

A Comparison of Geochemical Features of Extracts from Coal-Seams Source Rocks with Different Polarity Solvents

There exists a great difference in group-type fractions and biomarker distributions of chloroform extracts from coals and coal-seams oils, which makes the source identification of coal-seams oils in sedimentary basins rather difficult. The experiment, in which four different polarity solvents, n-hexane, benzene, dichloromethane and chloroform, were used to extract 9 coal-seams source rocks and 3 typical lacustrine source rocks, showed that the yield of extracts increased gradually with increasing solvent polarity, among which obviously the proportion of n-alkanes gradually decreased and the composition of the n-hexane extract was the most similar to that of coal-formed oils. Although some obvious differences existed in yields and compositions of the extracts obtained by different solvents, the entire distribution features of their n-alkanes, isoprenoids and sterane and terpane biomarkers remained, in general, similar, showing no distinct enrichment or depletion for a certain fraction by any solvent. The compositional analysis on n-hexane and chloroform extracts showed that the absolute amount (concentration) of biomarkers was relatively low for the n-hexane extract but comparatively high for the chloroform extract, this difference became great among coal-seams source rocks but small among lacustrine mudstones. The statistical analysis on the relative amount of the 18 major biomarkers in n-hexane and chloroform extracts from 10 source rock samples showed that extracts with a proportional error for the same biomarker of less than 5% (including the analytical error) accounted for 84% while those with a proportional error over 10% amounted to below 5%. This suggested that the difference in solvent polarity would lead to variations in both the relative amount of n-alkanes and the absolute amount of biomarkers for the extract from coals but could not induce variations in the distributional features and mutual ratios of biomarkers for the same extract on condition of using common solvents, consequently, the outcome of oil-source correlation made by these biomarkers will be independent of variations in amounts of saturates and biomarkers arising from solvent polarity. Therefore, biomarkers obtained from organic-rich source rocks including coals by the extraction with the commonly used chloroform solvent can be applied for the oil-source correlation of coal-seams petroliferous basins.

Molecular Organic Geochemistry of Crude Oil from Shushan and Abu Gharadig Basins, Western Desert, Egypt

Eight crude oil samples recovered from eight fields located in Abu Gharadig and Shushan basins in the north Western Desert, Egypt, were geochemically assessed in order to understand their genetic relationships. Two genetic families of oil are identified in this study, namely Abu Gharadig and Shushan oil families. Bulk (API and sulphur contents), n-alkanes, isoprenoids, biomarkers terpanes and steranes, and dibenzothiophene and phenanthrene parameters of the oils of the two families suggest regional variations of organic facies in their source rocks. Shushan samples represent oil typically generated from clay-rich terrigenous source rocks with great higher plant input, deposited under oxic conditions. Contrary, Abu Gharadig oil samples are of marine origin, their source rocks are rich in clay content and were deposited under suboxic environment. Biomarker maturity parameters Ts/Ts+Tm, ββ/αα and 20S/(20S+20R) C29 sterane ratios indicate that the studied samples had reached the peak of the oil window, with high maturity level biased towards Abu Gharadig oil. None of the studied oils have undergone biodegradation or water washing. This explains much of the chemical and physical properties uniformity observed across individual oil samples in each basin.