A comparison of organosulphur compounds produced by pyrolysis of asphaltenes and those present in related crude oils and tar sands

Asphaltenes and NSO fractions from a variety of oils and tar sands have been characterized by pyrolysis-gas chromatography (Py---GC) using both flame ionization and flame photometric detectors. Organosulphur compounds were not always produced by pyrolysis of the asphaltenes isolated from the biodegraded tar sand extracts although pyrolysis of the NSO fractions produced a series of thiophenes from all of the samples examined. These observations suggest that under certain conditions, asphaltene fractions may be affected by biodegradation, leading to preferential removal of the sulphur containing compounds. In addition, it was observed that Py---GC of asphaltenes permitted oils to be differentiated on the basis of their source rock lithology. Oils derived from carbonate source rocks produced thiophene/benzothiopene ratios <1 whilst the same ratio was >1 for oils derived from shales. Thiophene/dibenzothiophene ratios could be used in a similar manner.     

Carbon isotopic composition of individual n-alkanes in asphaltene pyrolysates of biodegraded crude oils from the Liaohe Basin, China

Biodegraded oils are widely distributed in the Liaohe basin, China. In order to develop effective oil-source correlation tools specifically for the biodegraded oils, carbon isotopic compositions of individual n-alkanes from crude oils and their asphaltene pyrolysates have been determined using the gas chromatography–isotope ratio mass spectrometry technique. No significant fractionation in the stable carbon isotopic ratios of n-alkanes in the pyrolysates of oil asphaltenes was found for anhydrous pyrolysis carried out at temperatures below 340°C. This suggests that the stable carbon isotopic distribution of n-alkanes (particularly in the C₁₆–C₂₉ range) in the asphaltene pyrolysates can be used as a correlation tool for severely biodegraded oils from the Liaohe Basin. Comparison of the n-alkane isotopic compositions of the oils with those of asphaltene pyrolysates shows that this is a viable method for the differentiation of organic facies variation and post-generation alterations.     

Biomarker distributions in asphaltenes and kerogens analysed by flash pyrolysis-gas chromatography-mass spectrometry

Biomarker distributions in a suite of asphaltenes and kerogens have been analysed by flash pyrolysis directly coupled to a GCMS system. Attention has been focussed on biomarkers of the sterane and triterpane types. The sample suite under investigation consists of sediments with different kerogen types and some crude oils. Biomarker distributions in the pyrolysates have been compared with the “free” biomarkers in the corresponding saturated hydrocarbon fractions.The analyses show significant differences between the distributions of the free biomarkers and those in the pyrolysates. The latter have lower amounts of steranes while diasteranes are absent or present at low concentrations only. In the triterpane traces a shift of maximum intensity from C₃₀ (free compounds) to C₂₇/C₂₉ is observed. Furthermore, the pyrolysates contain a set of triterpenes (not present among the free compounds), and there is a selective loss of “non-regular” triterpanes that are present in the saturated hydrocarbon fractions. The observed differences between pyrolysates and free hydrocarbons can be explained partly by the processes occurring during pyrolysis such as bond rupture and subsequent stabilisation of primary pyrolysis products. To a certain extent these differences also show that maturation processes occurring in sediments have effects on free biomarker molecules different from those on molecules that are enclosed in a macromolecular matrix (kerogen or asphaltenes).Differences between biomarker distributions of asphaltene and kerogen pyrolysates are relatively small. A comparison with the pyrolysates from extracted whole sediments suggests that these differences are mainly caused by interactions between the organic material and the mineral matrix during pyrolysis.Oil asphaltenes behave differently from sediment asphaltenes as their pyrolysates are more similar to the corresponding saturated hydrocarbon fractions, i.e. the differences described above are observed to a much smaller extent. This different behaviour appears to be the result of coprecipitation of a part of the maltene fraction with the oil asphaltenes.     

Geochemical significance of chemical composition and ESR properties of asphaltenes in crude oils from Alberta,Canada

More than 100 crude oils and 12 oil sands from Alberta, Canada, from stratigraphie units ranging in age from Upper Cretaceous to Middle Devonian, were processed to separate the asphaltenes which were then analysed for C, H, N, O and S and the ESR spectra run to determine g-value, spin number and line width. A factor analysis of these data, together with selected crude oil and reservoir properties, was interpreted in terms of a number of non-thermal processes which can affect the content and composition of asphaltenes during and after thermal maturation. Experiments on the effect of temperature on the signal intensity of free radicals indicate that more than half, and possibly all, the free radicals observed in asphaltenes must arise from charge transfer or closely related equilibria. An important solvent effect is demonstrated in further experiments, in which the more polar the solvent, the more the solvent dispersive forces overcome the associative forces of the asphaltene layers thus leading to lower molecular weights and a change in the charge transfer forces responsible for the ESR signal. The average molecular weight of asphaltenes from heavy, asphaltic, biodegraded crude oils and oil sands is considerably greater than the average molecular weight of asphaltenes from the more paraffinic, mature, non-biodegraded crude oils, and it seems likely that the differences in molecular weight of these asphaltenes are due to the solvent effect of the crude oils, and thus the laboratory observations have been confirmed in the Alberta basin.     

Evaluating the timing of oil expulsion: about the inverse behaviour of light hydrocarbons and oil asphaltene kinetics

This paper deals with natural temperature records in the heavy (asphaltenes) and the light fractions (C₇—light hydrocarbons) of petroleum. Two sets of marine oils formed from different source rocks and petroleum systems were studied using asphaltene kinetics and light hydrocarbon analysis. Both fractions have been reported to contain information about the temperature the respective oils have been exposed to in the subsurface. These indicated temperatures generally correspond to the conditions in the source rock when expulsion occurred. Bulk kinetic analysis of reservoir oil asphaltenes as well as light hydrocarbon (LH) analysis (of dimethylpentanes) were used here in order to evaluate the expulsion temperatures. Surprisingly, when considering information coming from both fractions, an inverse trend between LHs expulsion temperatures (Ctemp) and asphaltenes (Tasph.) can be observed—high T_asph (asphaltene temperatures) occur with low LH C_temp (light hydrocarbon expulsion temperatures) and low T_asph can be observed when Ctemp is high. These differences are of fundamental importance for the use of such geochemical data in calibrating numerical basin models. The reason for this inverse behaviour is possibly due to the different expulsion behaviour of light hydrocarbons and the heavy fraction of oils, especially when the source rocks contain only moderate amounts of organic matter. In addition it has to be considered that the temperature predictions obtained using asphaltene kinetic analysis are related to the onset temperature of petroleum expulsion, while light hydrocarbons provide, at best, average expulsion temperatures.     

New Technology of Optimizing Heavy Oil Reservoir Management by Geochemical Means：A Case Study in Block Leng 43,Liaohe Oilfield,China

Geochemical methods can be used to optimize heavy oil reservoir management.The distribution of some biomarkers in oils is different with the degree of biodegradation.Geochemi-cal parameters can be used to predict oil viscosity and thus to preliminarily evaluate the difficult-ties involved in oil production.The results of viscosity prediction for oils from reservoir S3^2 in block Leng 43 and preliminary evaluation of oil production difficulty are consistent with the geological data.     

9 and 34 GHz EPR study of the free radicals in various asphaltenes: Statistical correlation of the g-values with heteroatom content

The 9 and 34 GHz EPR spectra of eight asphaltenes from different locations have been studied at 294 K in an attempt to correlate the observed g-values with the heteroatom content. It is found that the EPR linewidths are larger and the g-values are smaller at 34 GHz than at 9 GHz. Quantitative statistical analysis of the g-values observed in those asphaltenes derived from tar sand bitumens and crude oils shows that they are uncorrelated with the heteroatom content, unlike those from coal. It is concluded that g-values may not be a good analytical tool for elucidating the structure of those asphaltenes not derived from coal.     

Comparative studies on compounds occluded inside asphaltenes hierarchically released by increasing amounts of H2O2/CH3COOH

Being the heaviest fraction of crude oils, asphaltenes are liable to aggregate, and other molecules in the oils can be steadily adsorbed onto, and even occluded inside the macromolecular structures of the asphaltenes. These occluded compounds inside the asphaltenes can survive over geological time in oil reservoirs owing to effective protection by the macromolecular structures of the asphaltenes. The asphaltenes of a crude oil (ZG31) from the central Tarim Basin, NW China, were hierarchically degraded by increasing the amount of H₂O₂/CH₃COOH to release the occluded compounds. Besides the common components, series of even numbered n-alk-1-enes and 3-ethylalkanes were detected among the occluded compounds. Comparison of the biomarker distributions and the compound-specific C isotopic results between the compounds from the maltenes and those from the occluded fraction, the ZG31 reservoir was suggested to have been charged multiple times, with different charges being derived from different strata of source rocks.     

Ruthenium-ion-catalyzed oxidation of asphaltenes and oil-source correlation of heavy oils from the Lunnan and Tahe oilfields in the Tarim Basin, NW China

The identification of marine source rocks in the Tarim Basin is debated vigorously. The intention of this paper is to investigate the asphahenes in heavy oils from the Lunnan and Tabe oilfields and Well TD2 with ruthenium-ions-catalyzed oxidation technique (RICO), in order to explore its role in oil-oil and oil-source correlations, The RICO products included n-alkanoic acids, α,ω-di-n-alkanoic acids, branched alkanoic acids, tricyclic terpanoic acids, hopanoic acids, gammacerane carboxylic acid , regular sterane carboxylic acids and 4-methylsterane carboxylic acids. The n-alkyl chains and biomarkers bounded on the asphaltenes were of unsusceptibility to biodegradation. The distribution and absolute concentrations of n-alkanoic acids in the RICO products of heavy oils from the Lunnan and Tabe oilfields are different from those of Well TD2. The biomarkers bounded on the asphahenes, especially steranes, have a distribution trend similar to that of the counterparts in saturates. The sterane carboxylic acids and 4-methylsterane carboxylic acids in the RICO products of heavy oils from the Lunnan and Tahe oilfields, dominated by C30 sterane and C31 4-methylsterane carboxylic acids, respectively, are significantly different from those of the heavy oils of Well TD2, whose dominating sterane and 4-methylsterane carboxylic acids are C28 sterane and C29 4-methylsterane acids, respectively. The RICO products of the asphaltenes further indicate that the Middle-Upper Ordovician may be the main source rocks for heavy oils from the Lunnan and Tabe oilfields.     

Geochemical characteristics of Tertiary oils derived from siliceous sources in Japan, Russia and U.S.A.

Siliceous sourced Tertiary oils from the Circum-Pacific area of Japan, Russia and the U.S.A. have a heavy carbon isotope composition, monomodal n-alkane distributions, and nearly identical regular sterane compositions with a predominance of C₂₇ homologues. These are consistent with open marine depositional environments dominated by diatomaceous organic matter. However, a number of alkane and biomarker parameters such as Pr/Ph, CPI, relative concentration of 28,30-bisnorhopane, and the C₃₅/C₃₄ homohopane ratio indicate more oxic depositional environments for the source rocks of Japan and Russia. In contrast to the California Monterey Formation sourced oils, petroleums with low maturity levels from the North Sakhalin basin, Russia and the Akita basin, Japan have lower concentrations of asphaltenes and sulphur and are characterized by higher API gravities. A correlation of extractable organic matter from source rocks vs the least matured petroleums demonstrates that oil expulsion in siliceous shales of the Akita basin occurs at a maturity level corresponding to R_o≥0.65%, which is in the range of the conventional oil window (R_o = 0.6−1.1%).     

Biological marker distribution in coexisting kerogen, bitumen and asphaltenes in Monterey Formation diatomite, California

Organic-rich (18.2%) Monterey Formation diatomite from California was studied. The organic matter consist of 94% bitumen and 6% kerogen. Biological markers from the bitumen and from pyrolysates of the coexisting asphaltenes and kerogen were analyzed in order to elucidate the relationship between the various fractions of the organic matter. While 17 alpha(H), 18 alpha(H), 21 alpha(H)-28,30-bisnorhopane was present in the bitumen and in the pryolysate of the asphaltenes, it was not detected in the pyrolysates of the kerogen. A C40-isoprenoid with "head to head" linkage, however, was present in pyrolysates of both kerogen and asphaltenes, but not in the bitumen from the diatomite. The maturation level of the bitumen, based on the extent of isomerization of steranes and hopanes, was that of a mature oil, whereas the pyrolysate from the kerogen showed a considerably lower maturation level. These relationships indicate that the bitumen may not be indigenous to the diatomite and that it is a mature oil that migrated into the rock. We consider the possibility, however, that some of the 28,30-bisnorhopane-rich Monterey Formation oils have not been generated through thermal degradation of kerogen, but have been expelled from the source rock at an early stage of diagenesis.     

Source of 1,2,3,4-tetramethylbenzene in asphaltenes from the Tarim Basin

1-Alkyl-2,3,6-trimethylbenzenes and a high relative amount of 1,2,3,4-tetramethylbenzene (TTMB) have been previously detected in the marine oils and asphaltenes in the oils from the Tarim Basin. In the present study, the stable carbon isotopic compositions of TTMB and n-alkanes in the pyrolysates of asphaltenes in the marine oils from the northern Tarim Basin and Silurian tar sands from the Tarim Basin were determined. TTMB has stable carbon isotopic compositions in the range from −23‰ to −24‰ and are about 12‰ more enriched in ¹³C than concomitant n-alkanes (−35‰ to −37‰) in the pyrolysates. The results indicate a contribution from green sulfur bacteria (Chlorobiaceae) to TTMB. Thus, the depositional environments of the source rocks for the marine oils and the bitumen in tar sands from the Tarim Basin are characterized by periods of euxinic conditions within the photic zone.     

The influence of biodegradation on resins and asphaltenes in the Liaohe Basin

Asphaltenes are traditionally considered to be recalcitrant to microbial alteration. Resins and asphaltenes of seven biodegraded oils extracted from reservoir cores of two columns (Es3 and Es1) of the Lengdong oilfield in the Liaohe Basin, NE China, were studied to test this hypothesis. Elemental (C, H, N, O, S) and isotopic compositions (δ¹³C and δ¹⁵N) were measured, FT-IR was used to study the oxygenated functionalities of both resins and asphaltenes, and Py–GC–MS was used to elucidate how alkyl side chains of asphaltenes were altered during biodegradation. We conclude that the products of biodegradation, such as carboxylic acids, phenol and alcohols, may not only contribute to the resin fraction of crude oils, but also are linked with functionalities of resins and asphaltenes. The amount of asphaltenes increases because some resin molecules are enlarged and their polarity increased such that they can be precipitated by hexane as newly generated asphaltenes. Thus, the hydrocarbons that are progressively consumed during biodegradation can pull the δ¹³C of asphaltene fraction closer to the δ¹³C of the altered resins and hydrocarbons that were consumed.     

沥青质傅里叶变换红外光谱 (FT IR)分析及其在有机地球化学研究中的应用

沥青质傅里叶变换红外光谱（FT－IR）分析可以反映出其分子结构上的特征，红外吸收因子Z[I(1380cm^-1)/I(720cm^-1）]能指示不同来源沥青质的母质类型；吸收因子Y[I(1600cm^-1)/I(1450cm^-1)]可以较好地讨论沥青质的成熟度演化状况；沥青质的红外研究认为，所有的沥青质都具有较好的再生烃潜力，其中Ⅲ型母质来源的沥青质具有较好的再生气潜力。而Ⅰ和Ⅱ型母质来源的沥青质具有高的再生油潜力。     

塔里木盆地哈拉哈塘凹陷东西两侧海相稠油地球化学特征：以LG7井和DH1-6-9井稠油为例

塔里木盆地哈拉哈塘凹陷东侧轮古地区有丰富的海相稠油产出,其中包括大型的塔河油田群,在凹陷的西北缘也有海相稠油发现。凹陷东侧海相稠油的地球化学成因已经有较多的研究报道,而西北缘针对海相稠油的研究工作仍然十分薄弱,其地球化学成因仍需深入探讨。本工作以哈拉哈塘凹陷东西两侧的稠油LG7井和DH1－6－9井为例,对比研究其地球化学特征,重点对比分析稠油沥青质中吸附／包裹烃类化合物的地球化学应用。研究结果表明凹陷东西两侧的稠油藏至少经历了两期油气的充注,其中第一期充注来自同一套烃源岩,后期遭受了,严重的生物降解改造;第二期充注来自另一套烃源岩,其正构烷烃仍然具有完整的分布模式。凹陷两侧稠油经历了相似的后期成藏过程,在西北缘相应的构造单元中可望发现更多海相来源的油气资源。     

Oxidation inhibitors occuring in bioproducers, recent sediments, ancient rocks and oils

Native antioxidants (AO) are involved in the transformation of organic matter (OM) in different stages of diagenesis. In the early stages, the geochemical significance of AO can be estimated by using AO consumption index (I). The positive I values suggest that the OM fossilization proceeded under reducing conditions which favoured the formation of oil-source rocks, while the negative I values indicate oxidizing conditions which are characterized by the formation of rocks having a low oil-generation potential. In the late stages of diagenesis, the AO content is indicative of the degree of catagenic (thermal) or biodegradation (oxidative) transformation of oils. The AO contents of Paleogenic, Mesozoic and Paleozoic oils have been found to differ approximately by one order of magnitude. A major portion of AO is concentrated in oil resins and asphaltenes. The ratio of AO to resins and asphaltenes can be used as criterion of catagenic transformation of OM.     

柯坪隆起阿克苏油苗的地球化学特征及其成因研究

柯坪隆起区是塔里木盆地海相烃源岩露头发育较好的地区之一,但相关的油气研究报道不多。本文详细研究了塔里木盆地柯坪隆起区油苗的有机地球化学特征并进行了相关的成因分析。阿克苏油苗经历了严重的生物降解作用,饱和烃生物标志物所能提供的成因信息十分有限。原油沥青质组分及储层吸附/包裹烃受后生作用影响较小,综合分析油苗沥青质热解产物与吸附/包裹烃的生物标志物及其碳同位素组成可以获得更多有效的成因信息。研究结果表明,阿克苏油苗与其储层吸附/包裹烃具有不同来源。油苗、沥青质以及沥青质热解产物的碳同位素特征与已经报道的多数海相原油及其沥青质较为接近,与典型的寒武系烃源来源的原油差异显著。而储层吸附/包裹烃与已报道的典型寒武系烃源岩来源油的生物标志物及碳同位素特征比较类似,可能形成于较高的热演化阶段。     

Chemical structural units of macromolecular coal components

Chemical degradations of coal resins, coal asphaltenes and coal residues have been performed with selective, non-oxidative reagents. The coal comprise samples a rank interval 0.30–1.21 %R_m. Degraded low-molecular-weight compounds were analyzed by GC-MS. The distributions of pentacyclic terpanes, isoprenoids, n-alkanes, acids and alcohols obtained as degradation products illustrate a considerable variability between the macromolecular coal fractions. A structural study on the molecular level of the degraded compounds from coal resins and coal asphaltenes show their potential to generate hydrocarbons during coalification process.     

Hydrous pyrolysis of Monterey asphaltenes

Hydrous pyrolysis of asphaltenes has been tested as a method to reconstruct the chemical composition of biodegraded oils and oil seeps. The asphaltenes of three oils (a nondegraded oil, a biodegraded oil, and a biodegraded oil seep) from the Monterey Formation were studied. Results show that the aliphatic fraction generated by hydrous pyrolysis is very similar in chemical composition to the non-degraded oil. This makes the method very useful in correlation studies of biodegraded and nondegraded oils. It also allows to roughly estimate the maturity of the source of the biodegraded oil or oil seep.     

Thermal depolymerization of kerogen and formation of immature oil

Two Chinese immature oil shales from the continental deposits of kerogen type I and II have been thermally treated combined with the technique of supercritical fluid extraction at 630–650 K and 15–25 MPa in a semi-continuous laboratory scale apparatus. Toluence is selected as the solvent. Up to 70–80% of the kerogen matrix can be converted to a thermal bitumen and extracted simultaneously. The chemical structural parameters from the NMR, IR, XRD, ESR and EA analyses of the kerogen and the thermal bitumen show striking resemblance in nature. It implies that the thermal bitumen is primarily a depolymerized product of the kerogen. Based on the GC/MS spectra of the aliphatic eluate of the thermal bitumen, the predominance of the odd/even ratio of the alkanes and the epimeric ratios, such as 20S(20S + 20R) of C-29 steranes and 22S/(22S + 22R) of C-32 terpanes, show that the maturity of the thermal bitumen from these oil shales is comparable to that of commercial immature oils from East China. The thermal bitumen is thought to be an intermediate product of the thermal degradation of kerogen.Since the thermal bitumen is mainly composed of asphaltenes and resins, it has a structure of gel. The gel-state bitumen may turn to sol-state readily due to its low aromaticity and polarity, or due to selective adsorption of asphaltenes by clay minerals. Then the migration potential of the bitumen is enhanced.Consequently, under favorable geological conditions, the thermal depolymerization of kerogen seems to be a probable mechanism to explain the formation of immature oils.