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1.
Twenty crude oil samples from the Murzuq Basin, SW Libya (A‐, R‐ and I‐Fields in Blocks NC115 and NC186) have been investigated by a variety of organic geochemical methods. Based on biomarker distributions (e.g. n‐alkanes, isoprenoids, terpanes and steranes), the source of the oils is interpreted to be composed of mixed marine/terrigenous organic matter. The values of the Pr/Ph ratio (1.36–2.1), C30‐diahopane / C29 Ts ratio and diasterane / sterane ratio, together with the low values of the C29/ C30‐hopane ratio and the cross‐plot of the dibenzothiophene/phenanthrene ratio (DBT/P) versus Pr/Ph ratio in most of oil samples, suggest that the oils were sourced from marine clay‐rich sediments deposited in mild anoxic depositional environments. Assessment of thermal maturity based on phenanthrenes, aromatic steroids (e.g. monoaromatic (MA) and triaromatic (TA) steroid hydrocarbons), together with terpanes, and diasterane/sterane ratios, indicates that crude oils from A‐Field are at high levels of thermal maturity, while oils from Rand I‐Fields are at intermediate levels of thermal maturity. Based on the distributions of n‐alkanes and the absence of 25‐norhopanes in all of the crude oils analysed, none of the oils appear to have been biodegraded. Correlation of the crude oils points to a single genetic family and this is supported by the stable carbon isotope values. The oils can be divided into two sub‐families based on the differences in maturities, as shown in a Pr/nC17 versus Ph/nC18 cross‐plot. Sub‐family‐A is represented by the highly mature oils from A‐Field. Sub‐family‐B comprises the less mature oils from R‐ and I‐Fields. The two sub‐families may represent different source kitchens of different thermal maturity or different migration pathways. In summary, the geochemical characteristics of oil samples from A‐, R‐, and I‐Fields suggest that all the crude oils were generated from similar source rocks. Depositional environment conditions and advanced thermal maturities of these oils are consistent with previously published geochemical interpretations of the Rhuddanian “hot shale” in the Tanezzuft Formation, which is thought to be the main source rock in the Murzuq Basin. 相似文献
2.
《Petroleum Science and Technology》2013,31(9-10):1057-1070
ABSTRACT Maturity-dependent trends of a number of biomarker and nonbiomarker geochemical parameters were examined in crude oils from the Western Desert and the Gulf of Suez, Egypt. Molecular maturity assessments showed that all oils are at an advanced level of thermal maturity, and many ratios, such as CPI, hopane/hopane + moretane, C31 22S/22S + 22R hopanes and C29 ααα-20S/20S + 20R steranes were almost identical and have reached their thermal equilibrium values. Changes in the Ts/Tm and C29 ββ/(ββ + αα) steranes however, showed a more advanced level of thermal maturity for Umbaraka oil. On the other hand, correlations utilizing the nonbiomarkers API gravity, ΣV, Ni, sulfur content, sat/arom, and Ph/n-C18 ratios did show more distinct differences and are consistent between the oils. 相似文献
3.
Nine crude oils and eight source rock samples from Cretaceous sequences, Lower Indus Basin have been characterized by means of diagnostic biomarker parameters in order to establish genetic liaison among them. The biomarker geochemistry indicators such as relative distribution of C27-C28-C29 ααα-20R steranes, C19 and C23 tricyclic terpanes (TT), C24 tetracyclic terpanes (TeT), hopanes distribution, steranes/hopanes ratio, presence of unidentified compound X (C30 pentacyclic triterpane), and pristane (Pr) to phytane (Ph) ratio suggest that the crude oils contain predominantly terrigenous organic matter (OM). Based on these data, the analyzed crude oils from the Lower Indus Basin are genetically associated and could be classified into a single group. Geochemical correlation studies of crude oils and source rock sediments indicate that Lower Goru shales and Sembar could be the probable source rocks for the petroleum generated from Cretaceous strata, Lower Indus Basin, Pakistan. 相似文献
4.
Ruiliang Guo Xiuqin Deng Peng Song Lewei Hao Bing Tian 《Petroleum Science and Technology》2013,31(24):2070-2076
AbstractFour oil-bearing sandstone samples of Chang 8 sub-unit were collected from Ordos basin and geochemical characteristics of hydrocarbon in different states during oil-filling process were determined. The occurrence of hydrocarbon in sandstone can be divided into four types by using sequential extraction. The features of alkanes, the diagram of Pr/nC17 versus Ph/nC18 and the cross plot of MPI-1 versus Rc show that four type hydrocarbons derived from same source rock, the organic matter includes aquatic organisms and higher plants, moreover, the thermal maturity of the free hydrocarbon is the highest, followed by the sealed hydrocarbon and the cement hydrocarbon, and the inclusion hydrocarbon is the lowest. The variation of geochemical features of hydrocarbons in different states may result from continuous oil-charging in geological history. 相似文献
5.
AbstractGeochemical evaluation of oil samples from the eastern part of the Niger Delta divided into western, eastern, and central sections of the study area was carried out for the characterization of their light hydrocarbons content in order to correlate oils from different parts. The hydrocarbons in the oil samples were determined using gas chromatographic (GC) technique. The results obtained showed that CPI, Pr/Ph, Pr/nC17, and Ph/nC18 ratios ranged from 0.99–1.55, 2.19–4.79, 0.92–2.35, and 0.27–0.47, respectively. The Pr/nC17 versus Ph/nC18 plot showed that the oils were derived from terrestrial organic materials that were deposited under oxic to suboxic conditions. They are moderately matured with minimal effect of biodegradation on most of the oil samples although two of the oils showed relatively higher degradation. Both bivariate and multivariate plots of the light hydrocarbon ratios differentiated the western and central oils from the eastern oils. The classification of the oils into families was not based on origin but rather on post generative alterations that include reservoir conditions and possibly migration effects. The light hydrocarbon parameters identified can be used in the correlation tools. 相似文献
6.
This study presents a systematic geochemical analysis of Paleogene crude oils and source rocks from the Raoyang Sag in the Jizhong sub-basin of the Bohai Bay Basin (NE China). The geochemical characteristics of fifty-three oil samples from wells in four sub-sags were analysed using gas chromatography (GC) and gas chromatography – mass spectrometry (GC-MS). Twenty core samples of mudstones from Members 1 and 3 of the Eocene-Oligocene Shahejie Formation were investigated for total organic carbon (TOC) content and by Rock-Eval pyrolysis and GC-MS to study their geochemistry and hydrocarbon generation potential. The oils were tentatively correlated to the source rocks. The results show that three groups of crude oils can be identified. Group I oils are characterized by high values of the gammacerane index and low values of the ratios of Pr/Ph, Ts/Tm, 20S/(20S+20R) C29 steranes, ββ/(ββ+αα) C29 steranes, C27 diasteranes/ C27 regular steranes and C27/C29 steranes. These oils have the lowest maturity and are interpreted to have originated from a source rock containing mixed organic matter deposited in an anoxic saline lacustrine environment. The biomarker parameter values of Group III oils are the opposite to those in Group I, and are interpreted to indicate a highly mature, terrigenous organic matter input into source rocks which were deposited in suboxic to anoxic freshwater lacustrine conditions. The parameter values of Group II oils are between those of the oils in Groups I and III, and are interpreted to indicate that the oils were generated from mixed organic matter in source rocks deposited in an anoxic brackish–saline or saline lacustrine environment. The results of the source rock analyses show that samples from Member 1 of the Shahejie Formation were deposited in an anoxic, brackish – saline or saline lacustrine environment with mixed organic matter input and are of low maturity. Source rocks in Member 3 of the Shahejie Formation were deposited in a suboxic to anoxic, brackish – saline or freshwater lacustrine environment with a terrigenous organic matter input and are of higher maturity. Correlation between rock samples and crude oils indicates that Group I oils were probably derived from Member 1 source rocks, while Group III oils were more likely generated by Member 3 source rocks. The Group II oils with transitional characteristics are likely to have a mixed source from both sets of source rocks. 相似文献
7.
ORGANIC GEOCHEMISTRY OF CRUDE OILS AND UPPER CRETACEOUS SOURCE ROCKS FROM CONCESSION 11, WEST SIRTE BASIN,LIBYA
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W. Sh. El Diasty S. Y. El Beialy K. E. Peters H. El Atfy A. M. Gheith N. N. Agha 《Journal of Petroleum Geology》2016,39(4):393-413
This paper reports the results of Rock‐Eval pyrolysis and total organic carbon analysis of 46 core and cuttings samples from Upper Cretaceous potential source rocks from wells in the West Sirte Basin (Libya), together with stable carbon isotope (δ13C) and biomarker analyses of eight oil samples from the Paleocene – Eocene Farrud/Facha Members and of 14 source rock extracts. Oil samples were analysed for bulk (°API gravity and δ13C) properties and elemental (sulphur, nickel and vanadium) contents. Molecular compositions were analysed using liquid and gas chromatography, and quantitative biological marker investigations using gas chromatography – mass spectrometry for saturated hydrocarbon fractions, in order to classify the samples and to establish oil‐source correlations. Core and cuttings samples from the Upper Cretaceous Etel, Rachmat, Sirte and Kalash Formations have variable organic content and hydrocarbon generation potential. Based on organofacies variations, samples from the Sirte and Kalash Formations have the potential to generate oil and gas from Type II/III kerogen, whereas samples from the Etel and Rachmat Formations, and some of the Sirte Formation samples, have the potential to generate gas from the abundant Type III kerogen. Carbon isotope compositions for these samples suggest mixed marine and terrigenous organic matter in varying proportions. Consistent with this, the distribution of n‐alkanes, terpanes and steranes indicates source rock organofacies variations from Type II/III to III kerogen. The petroleum generation potential of these source rocks was controlled by variations in redox conditions during deposition together with variations in terrigenous organic matter input. Geochemical analyses suggest that all of the oil samples are of the same genetic type and originated from the same or similar source rock(s). Based on their bulk geochemical characteristics and biomarker compositions, the oil samples are interpreted to be derived from mixed aquatic algal/microbial and terrigenous organic matter. Weak salinity stratification and suboxic bottom‐water conditions which favoured the preservation of organic matter in the sediments are indicated by low sulphur contents and by low V/Ni and Pr/Ph ratios. The characteristics of the oils, including low Pr/Ph ratio, CPI ~l, similar ratios of C27:C28:C29 ααα‐steranes, medium to high proportions of rearranged steranes, C29 <C30‐hopane, low Ts/Tm hopanes, low sulphur content and low V/Ni ratio, suggest a reducing depositional environment for the source rock, which was likely a marine shale. All of the oil samples show thermal maturity in the early phase of oil generation. Based on hierarchical cluster analysis of 16 source‐related biomarker and isotope ratios, four genetic groups of extracts and oils were defined. The relative concentrations of marine algal/microbial input and reducing conditions decrease in the order Group 4 > Group 3 > Group 2 > Group1. Oil – source rock correlation studies show that some of the Sirte and Kalash Formations extracts correlate with oils based on specific parameters such as DBT/P versus Pr/Ph, δ13Csaturates versus δ13Caromatics, and gammacerane/hopane versus sterane/hopane. 相似文献
8.
O. L. Faboya O. O. Sonibare Z. Liao O. Ekundayo Y. Tian 《Petroleum Science and Technology》2013,31(11):1253-1266
The occurrence and distributions of carbazole compounds were investigated in crude oils from Niger Delta, Nigeria, by gas chromatography-mass spectrometry-mass spectrometry. Geochemical characterization of the oils and the available source rocks based on saturate and aromatic biomarkers showed that the oils have higher thermal maturity than the source rocks. All the oils are isotopically related and might have originated from the same source rocks. However, subtle maturity differences exist among the oils from the same field. C2- carbazoles are the dominant components of the crude oils. 4-methylcarbazole is the most abundant of the methylcarbazoles isomers while 1,5-dimethylcarbazole occurs as the most abundant among the dimethylcarbazoles. The abundance of benzocarbazoles are low compared to the alkylcarbazoles. Cross plots of the methylcarbazoles and dimethylcarbazoles against Pr/Ph ratio showed that carbazoles distributions in the oils are not affected by source facies. However, the cross plots of C1- carbazoles and C2- carbazoles against the calculated vitrinite reflectance indicated that the carbazoles concentrations increase with increasing maturity. 相似文献
9.
`The present work aims to study the organic chemistry, the generation and maturation of the hydrocarbons encountered at Abu Roash Formation, Wadi El Rayan oil field. The analysis of source rocks indicates the presence of two organic facies. The first is characterized by high total organic carbon of 0.93–3.39%, strongly oil-prone (Type II), and good potential for oil generation (pyrolysis S2 yields 4.54–23.26 mg HC/g rock and HI 488–705 mg HC/g TOC). The second attains good range of organic carbon from 0.90% to 1.57%, which is a mixed oil and gas (Type II–Type III) of fair hydrocarbon generation (pyrolysis S2 yield of 1.98–5.33 mg HC/g). The kerogen type consists of unstructured lipids and some terrestrial material. Plot of Pr/n-C17 versus Ph/n-C18 indicates that the crude oil was derived from mixed source rock, while the maturity profile assigns oil windows (0.6 Ro%) matching topmost of Abu Roash G Member. 相似文献
10.
Commercial oil flow has been obtained from the sandstone reservoir of the Lower Silurian Kelpintag Formation in the Well Shun-9 prospect area.In the present studies,10 Silurian oil and oil sand samples from six wells in the area were analyzed for their molecular and carbon isotopic compositions,oil alteration(biodegradation),oil source rock correlation and oil reservoir filling direction.All the Silurian oils and oil sands are characterized by low Pr/Ph and C21/C23 tricyclic terpane(〈1.0) ratios,"V"-pattern C27-C29 steranes distribution,low C28-sterane and triaromatic dinosterane abundances and light δ13C values,which can be correlated well with the carbonate source rock of the O3 l Lianglitage Formation.Different oil biodegradation levels have also been confirmed for the different oils/oil sands intervals.With the S1k2 seal,oils and oil sands from the S1k1 interval of the Kelpintag Formation have only suffered light biodegradation as confirmed by the presence of "UCM" and absence of 25-norhopanes,whereas the S1k3-1 oil sands were heavily biodegraded(proved by the presence of 25-norhopanes) due to the lack of the S1k2 seal,which suggests a significant role of the S1k2 seal in the protection of the Silurian oil reservoir.Based on the Ts/(Ts+Tm) and 4-/1-MDBT ratios as reservoir filling tracers,a general oil filling direction from NW to SE has been also estimated for the Silurian oil reservoir in the Well Shun-9 prospect area. 相似文献
11.
M. M. El Nady 《Petroleum Science and Technology》2013,31(9):1063-1082
Abstract Crude oils together with extracts from the Middle Jurassic (Khatatba Formation), Barremian-Early Aptian Alam El Bueib Formation, and Early Albian Kharita Formation were collected from five wells (Ras Qattara-Zarif-5, Ras Qattara-Zarif-3, and Zarif-1, Zarif-2, SW Zarif-1) in the North Qattara Depression. Biomarkers (pristane/phytane, isoprenoids/n-alkanes, steranes, triterpanes, C29 steranes 20S/20S + 20R, C23 tricyclic/C30 hopane, Ts/Tm, C30 moretane/C30 hopane ratios, homohopane and gammacerane indices) of the saturated hydrocarbon fraction were analyzed in order to assess the source and maturity of the crude oils and the extracts. The results suggested that the oils from Khatatba and Alam El Bueib formations are mature, derived from source rocks containing marine and terrestrial organic matter, respectively. The source environments and maturity of the oil from the Khatatba Formation is similar to that of the Khatatba source rock extract. The oil from the Alam El Bueib formation differs from the extracts of the Alam El Bueib and Kharita formations. The Khatatba formation seems to be an effective source rock in the North Qattara Depression. 相似文献
12.
GEOCHEMISTRY AND ORIGIN OF UPPER CRETACEOUS OILS FROM THE TERMIT BASIN,NIGER 总被引:1,自引:0,他引:1
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Bang Liu Guangya Zhang Fengjun Mao Jiguo Liu Mingsheng Lü 《Journal of Petroleum Geology》2017,40(2):195-207
Crude oil samples (n = 16) from Upper Cretaceous reservoir rocks together with cuttings samples of Upper Cretaceous and Paleogene mudstone source rocks (n = 12) from wells in the Termit Basin were characterized by a variety of biomarker parameters using GC and GC‐MS techniques. Organic geochemical analyses of source rock samples from the Upper Cretaceous Yogou Formation demonstrate poor to excellent hydrocarbon generation potential; the samples are characterized by Type II kerogen grading to mixed Types II–III and III kerogen. The oil samples have pristane/phytane (Pr/Ph) ratios ranging from 0.73 to 1.27, low C22/C21 and high C24/C23 tricyclic terpane ratios, and values of the gammacerane index (gammacerane/C30hopane) of 0.29–0.49, suggesting derivation from carbonate‐poor source rocks deposited under suboxic to anoxic and moderate to high salinity conditions. Relatively high C29 sterane concentrations with C29/C27 sterane ratios ranging from 2.18–3.93 and low values of the regular steranes/17α(H)‐hopanes ratio suggest that the oils were mainly derived from kerogen dominated by terrigenous higher plant material. Both aromatic maturity parameters (MPI‐1, MPI‐2 and Rc) and C29 sterane parameters (20S/(20S+20R) and ββ/ (αα + ββ)) suggest that the oils are early‐mature to mature. Oil‐to‐oil correlations suggest that the Upper Cretaceous oils belongs to the same genetic family. Parameters including the Pr/Ph ratio, gammacerane index and C26/C25 tricyclic terpanes, and similar positions on a sterane ternary plot, suggest that the Upper Cretaceous oils originated from Upper Cretaceous source rocks rather than from Paleogene source rocks. The Yogou Formation can therefore be considered as an effective source rock. 相似文献
13.
This distribution of tricyclic terpanes in source rocks from the northwestern and central Niger Delta was used to evaluate their origin, depositional environment and thermal maturity. The rock samples were extracted using Soxhlet extraction method and the saturated hydrocarbon fraction was analysed for biomarkers using gas chromatography-mass spectrometry (GC-MS). The values of soluble organic matter (SOM) and total hydrocarbons for wells AW and OP source rock samples exceeded the minimum 500 ppm and 300 ppm, respectively with values indicating very good to excellent potential source rocks. The tricyclic terpane source parameters and the complementary distribution of hopanes, regular C27-C29 steranes, n-alkanes and acyclic isoprenoid hydrocarbons showed that samples from well AW consist of mixed marine/terrestrial organic matter while those from well OP consist of organic matter largely from terrestrial origin. The values of Pr/Ph ratio for source rock samples from wells AW and OP indicate deposition of the organic matter under suboxic conditions. Sterane and hopane biomarker maturity parameters indicated that the source rock samples from wells AW and OP are at onset of oil generation and main oil window, Most of the source rock samples from well AW are more thermally mature than those from well OP. The results of tricyclic terpane maturity parameters indicated low thermal maturity for the rock samples from both wells with samples from well AW more thermally mature than those from well OP. 相似文献
14.
Tatiana Montoy Blanca L. Argel Nashaat N. Nassar Camilo A. Franco Farid B. Corte′s 《石油科学(英文版)》2016,13(3):561-571
The production of heavy and extra-heavy oil is
challenging because of the rheological properties that crude
oil presents due to its high asphaltene content. The upgrading
and recovery processes of these unconventional oils are
typically water and energy intensive, which makes such
processes costly and environmentally unfriendly. Nanoparticle
catalysts could be used to enhance the upgrading and
recovery of heavy oil under both in situ and ex situ conditions.
In this study, the effect of the Ni-Pd nanocatalysts
supported on fumed silica nanoparticles on post-adsorption
catalytic thermal cracking of n-C7 asphaltenes was investigated
using a thermogravimetric analyzer coupled with
FTIR. The performance of catalytic thermal cracking of n-C7
asphaltenes in the presence of NiO and PdO supported on
fumed silica nanoparticles was better than on the fumed
silica support alone. For a fixed amount of adsorbed n-C7
asphaltenes (0.2 mg/m2), bimetallic nanoparticles showed
better catalytic behavior than monometallic nanoparticles,
confirming their synergistic effects. The corrected Ozawa–
Flynn–Wall equation (OFW) was used to estimate the
effective activation energies of the catalytic process. The
mechanism function, kinetic parameters, and transition state
thermodynamic functions for the thermal cracking process of
n-C7 asphaltenes in the presence and absence of nanoparticles
are investigated. 相似文献
15.
The composition and distribution of saturated hydrocarbons (alkanes, steranes, and terpanes) of oils from the Ulyanovsk oblast
of the Volga-Urals oil-and-gas basin were studied. Wax fractions were isolated from crude oils, and C48-C52 high-molecular-mass n-alkanes, C35-C52 alkylcyclopentanes, and C24-C42 2- and 3-monomethylalkanes were identified in these fractions. Based on the data on the composition of C10-C36
n-alkanes, C19-C35 terpanes, C21-C30 steranes, and C40+ alkanes, it was shown that the oils in question were generated by marine organic matter in carbonate sediments. Oil from
the Novolabitovskoe field (1981–1992 m) substantially differs for the other oils in terpane and sterane compositions. These
differences are supposedly due to another source of organic matter. 相似文献
16.
In this work, the oil seepage was found in calcite veins in Keluke formation of upper Carboniferous reservoirs. Based on the analysis of geochemical characteristics, the isomerization parameter of C29 sterane 20S/(20S + 20R) was obtained as 0.39 and Ts/Tm value as 1.12, indicating that the oil seepage was mature. The Pr/Ph value was 0.64 and the tricyclic terpane was characterized by high abundance of gamacerane, C27 > C29 sterane, and a normal distribution with C23 as the dominant peak. Moreover, the oil/oil and oil/source rock correlation of oil seepage and carboniferous source rock underground and surface indicated that the oil seepage was similar to crude in Mabei-2 well (1463 m) and Sin-3 well (1076 m) but was different from the other crude in north Qaidam basin. It is inferred that the oil seepage was authigenic crude in Carboniferous, and Carboniferous source rocks have contributed to the oils in Mabei-2 well (1463 m) and Sin-3 well (1076 m). This study offers new scientific evidence for the exploring of carboniferous in Qiandam basin. 相似文献
17.
In the Ere?li‐Uluk??la Basin, southern Turkey, crude oil shows have been observed in the subsurface in the shale‐dominated non‐marine Upper Miocene – Pliocene succession. Based on analyses of samples from four boreholes, the shales’ organic matter content, thermal maturity and depositional characteristics are discussed in this study. Geochemical correlations are established between shale extracts and a crude oil sampled from the shale succession. The shales have moderate to high hydrogen index (HI) and very low oxygen index (OI) values. Pyrolysis data show that the shales contain both Types I and II kerogen, and n‐alkane and biomarker distributions indicate that organic matter is dominated by algal material. Very high C26/C25 and C24/C23, and low C22/C21 tricyclic terpane ratios and C31 R/C30 hopane, C29/(C28+C29) MA and DBT/P ratios in shale extracts indicate that deposition occurred in a lacustrine setting. High gammacerane and C35 homohopane concentrations and low diasterane/sterane ratios with a very low Pr/Ph ratio suggest that both the shales and the source rocks for the oil were deposited in a highly anoxic environment in which the water column may have been thermally stratified. Although the shales analysed have very low Tmax values, the production index is quite high which suggests that the shales are early‐mature to mature. Biomarker ratios including C32 22S/(22R+22S) homohopanes, C29 20S/(20R+20S) and ββ(ββ+αα) steranes, moretane/hopane, TA(I)/TA(I+II) and MPI‐3 all suggest that the shales are within the oil window. Heavy components of free hydrocarbons (S1) within the shales may have been recorded as part of the Rock‐Eval S2 peak resulting in the low Tmax values. The oil and shale extracts analysed are similar according to their sterane and triterpane distributions, suggesting that the oil was generated by the shales. However burial depths of the Upper Miocene – Pliocene shale succession are not sufficient for thermal maturation to have occurred. It is inferred that intense volcanism during the Pliocene – Pleistocene may have played an important role in local maturation of the shale succession. 相似文献
18.
Mohammed Hail Hakimi Ismail M. Ismail Aref A. Lashin El-Khedr H. Ibrahim 《Petroleum Science and Technology》2019,37(8):899-906
Physical and geochemical properties were performed on three crude oils from Alif-01 well in the Marib sub-basin. The analyzed samples comprise medium specific gravity (37° API), reflecting mature source rocks. The thermal maturity of the analyzed oils is also indicated from the high content of aliphatic hydrocarbons (HC). The compositions of HC further suggest that analyzed oils belong to paraffinic oils. The n-alkane and isoprenoid distributions reveal that the analyzed oils are derived from marine source rock, containing mixed organic matter, with some terrestrial input and deposited under relatively reducing conditions. The features of the analyzed oils are consistent with the Madbi source rock characteristics in the basin. 相似文献
19.
ABSTRACT The acid fraction of crude oils and related source rocks of different stratigraphic units from the Gulf of Suez and Western Desert, Egypt were analyzed by GC and GC/MS. Normal alkanoic acids (n-C9?n-C30) were the dominant series (with the predominance of even-carbon numbers maximizing at n-C16, n-C18 or n-C22while iso- and anteiso- branched acids were minor constituents. All samples showed a preference of short chain acids (n-C10?n-C19 with respect to long chain acids (n-C20+) typical of marine oils and source rocks. The n-alkanoic acids distribution suggests a predominant algal and/or bacterial contribution. The presence of high relative abundance of mono and di-unsaturated carboxylic acids in a number of samples point to recent microbial activity. Distributions of n-alkanoic acids in the range (C12?C22) show striking similarities with the n-alkane distributions, indicating that both series may, at least in part, be diagenetically related by decarboxylation of the acids. Dehydroabietic acid has been identified in only one sample from Balaim Marine source rock. This resin-derived compound has probably been transported as pollen to the marine environment. 相似文献
20.
ABSTRACT Ten crude oil samples, covering wide range of maturity (API = 18.5?36.1), were assembled from Safaniya, Abqiq, Ain-Dar, Wafra, Marjan, and Zulf oil fields in the area of Arabian Gulf. Different analytical techniques, including liquid chromatographic separation, gas chromatography, and nuclear magnetic resonance spectroscopy, were used to characterize the oil samples. Some bulk and specific compositional parameters were used for oil-oil correlations in order to evaluate thermal maturation, origin, biodegradation and depositional environments of the crude oils. Considering the maturity relationships, it was suggested that the bulk composition of Wafra/Iucene crude oil was altered due to biodegradation and vertical migration. Correlation between API gravity and PAP of aromatic fraction indicated two maturity levels of onshore and offshore oil fields. The distribution of n-alkanes reflected the marine origin of the crude oils. Isoprenoids/n-alkanes and pristane/phytane ratios were determined by capillary GC of a middle distillate of the crude oil samples. The correlations showed that the oil samples, except for those collected from Wafra oil field, are normal mature crude oils which were deposited under oxidizing environments. The much lower Pr/Ph ratio of Wafra/Iucene oil field could be considered as an indicator of reducing depositional environments. 相似文献