Geochemical Characteristics Of Crude Oils Research Articles

Geochemical characteristics of crude oils, their asphaltene and related organic matter source inputs from Fula oilfields in the Muglad Basin, Sudan

Bulk geochemical characteristics of crude oils, coupled with geochemical analyses of reservoir oil asphaltenes from Fula oilfields in the Muglad Basin, have provided information on source organic matter input, depositional environment and the correlation between these crude oils and their potential source rocks in the basin. Only one oil family is present within the Fula oilfields as indicated by biomarker and non-biomarker parameters. The Fula oils are characterized by moderate API gravity, low sulphur and moderate trace metal (Ni, V) contents, and high wax contents. This suggested that the oils were generated from source rock that was deposited in a principally lacustrine environment. This is supported by bulk geochemical characteristics and biomarker compositions. A variety of biomarker–specific parameters obtained from n-alkanes, regular isoprenoids, terpanes and steranes indicate that the Fula oils were generated predominantly from algae-derived organic matter that was deposited in a lacustrine environment which then experienced a slight seawater influence under suboxic to relatively anoxic conditions. These oils were generated from source rock with a wide range of thermal maturity ranging from early to peak oil window. The biomarker characteristics of these oils are consistent with those of the early Cretaceous Abu Gabra shales. The oil-source rock relationship is also demonstrated by similarities in the structural moieties of the Fula oil asphaltene and the Abu Gabra shale kerogens. The Pyrolysis GC of the analyzed Fula oil asphaltene indicates that the oils were derived from Type I-algal organic matter, consistent with paraffinic high wax oils.

Organic geochemical characteristics of crude oils and oil-source rock correlation in the Sunah oilfield, Masila Region, Eastern Yemen

The objective of this study is to provide information on source organic matter input, depositional conditions and the correlation between crude oils recovered from Sunah oilfield and Upper Jurassic Madbi Formation. A suite of twenty-six crude oils from the Lower Cretaceous reservoirs (Qishn clastic) of the Masila Region (Eastern Yemen) were analysed and geochemically compared with extracts from source rock of the Upper Jurassic (Madbi Formation). The investigated biomarkers indicated that the Sunah oils were derived from mixed marine and terrigenous organic matter and deposited under suboxic conditions. This has been achieved from normal alkane and acyclic isoprenoids distributions, terpane and sterane biomarkers. These oils were also generated from source rock with a wide range of thermal maturity and ranging from early-mature to peak oil window. Based on molecular indicators of organic source input and depositional environment diagnostic biomarkers, one petroleum system operates in the Masila Region; this derived from Upper Jurassic Madbi organic-rich shales as source rock. Therefore, the hydrocarbon exploration processes should be focused on the known location of the Upper Jurassic Madbi strata for predicting the source kitchen.

Geological, hydrogeochemical, and microbiological characteristics of the Oil site of the Uzon caldera (Kamchatka)

This study used geological, geochemical, and microbiological data to examine the Uzon oils and conditions within the Uzon caldera. The trace-element compositions of crude oils and solutions from boreholes and hydrothermal springs were determined by ICP-MS. The majority of hydrothermal manifestations within the Uzon caldera are controlled by three trends of faults. The major fault zone, trending nearly E-W, is located between Kikhpinych and Taunshits volcanoes. It acts as a magma conduit and hosts numerous oval-shaped hydrothermal vents. The Oil site is situated on the periphery of the hottest area of highest hydrothermal activity within the Eastern thermal field. On the Eh-pH diagram, most solutions of the Uzon caldera define distinct fields and trends which correlate with the stability fields for sulfur and iron. The Oil site is characterized by very wide variations in temperature and Eh-pH parameters of pore solutions. The geochemical signatures of the solutions at this site are broadly similar to those from other areas of the Uzon caldera, but differ in their sulfide ion and sulfate ion concentrations. These differences can be explained by mixing of deep chloride-sodium hydrothermal solutions and solutions produced during surface oxidation of sulfide-containing material. With respect to the average continental crust, the Uzon oil is enriched in S, As, and Hg. The crude oil and solutions have broadly similar concentrations of B, S, Cl, As, Se, Br, Cd, I, Hg, and Pb and highly variable concentrations of Ti, V, Cr, Co, Ni, Cu, Cd, Nb, and Sn. The community structure of archaeal assemblages in springs and test pits at the Eastern thermal field was analyzed by 16S rRNA library and pyro sequencing methods. It was found that the proportion of archaea in the microbial communities of the Uzon caldera ranges from 2 to over 70% of the total sequences identified. Crenarchaeota were found in large proportions in all samples except one. The majority of the sequences in four samples were affiliated with Euryarchaeota, which comprise methanogenic archaea, extreme halophiles, and some extreme thermophiles. The results of geological, mineralogical-geochemical, microbiological and physicochemical studies of oil seeps in the Uzon caldera reveal distinctive geochemical characteristics of crude oil and the complexity of oil formation.

Source controls on geochemical characteristics of crude oils from the Qionghai Uplift in the western Pearl River Mouth Basin, offshore South China Sea

The Qionghai Uplift is a sub-uplift tectonic unit in the western Pearl River Mouth Basin. Though lacking source rocks itself, it adjoins the Wenchang A sag, the Wenchang B sag and the Qionghai sag which contain significant source rocks. For the special geological background, the Qionghai Uplift has become an important accumulation area for oil and gas, and the oils in the uplift show significant variation in important geochemical parameters. In this study, the geochemistry of oils in the Qionghai Uplift oil pools has been analyzed systematically, revealing geographic differences. Three groups of oils were identified in the northern part of the Qionghai Uplift: Group I oils, represented by the WC8-3E oil pool located in the northeast; group II oils in the middle represented by the WC13-1 oil pool, and group III oils in the southwest represented by the QH18-1 oil pool. According to oil-source correlations, the oils of the three groups have mixed geochemical characteristics between typical oils sourced from the Enping Formation in the Wenchang A sag, and those sourced from the Wenchang Formation in the Wenchang B sag. We show that based on knowledge of hydrocarbon generation and evolution of source rocks around the Qionghai Uplift, as well as the formative features of traps within the uplift, the geochemical characteristics of the oils are mainly controlled by the distribution of mature hydrocarbon kitchens surrounding the Uplift. Oils in the northeast of the northern Qionghai Uplift were mainly sourced from the Enping Formation in the Wenchang A sag with a secondary contribution from the Wenchang Formation in the Qionghai sag. Oils in the middle section are of mixed origin from the Enping Formation in the Wenchang A sag and the Wenchang Formation in the Wenchang B sag. Oils in the southwest part of the northern Qionghai Uplift were mainly generated from the Wenchang Formation in the Wenchang B sag. This research provides guidance for future exploration of the Qionghai Uplift.

Geochemical characteristics of crude oil in fluvial deposits from Maling oilfield of Ordos Basin, China

Maling oilfield is one of the earliest discovered oilfields in the Ordos Basin. It is also a typical representative of oil reservoirs in fluvial deposits. However, due to the deficiency of geochemical study on the crude oils and source rocks, the interpretation of the oil origin is largely based on the geological situation. Maling crude oils (21) and source rocks (14) from the basin have been systematically analyzed. The distribution of the biomarkers indicates that the crude oils mainly originated from source rocks deposited under a weakly reducing to sub-oxic, freshwater lacustrine environment. Besides algae, higher land plants have also made an important contribution to the source organic matter. Comparison of the distributions of the biomarkers suggests that there is a correlation between the Maling oilfield oils and the source rocks of the Yanchang Formation.

Geochemical Characteristics of Crude Oils from the Tarim Basin by Fourier Transform Ion Cyclotron Resonance Mass Spectrometry

Nine marine and two terrestrial oils from the Tarim Basin in Western China were analyzed by Fourier transform ion cyclotron resonance mass spectrometry. Sulfur compounds with 8–47 carbon atoms and double-bond equivalent (DBE) values of 0–21 are abundant in the crude oils. The most abundant sulfur species in Tazhong marine oils are S1 species (80.57–85.22%), followed by O1S1 (6.95–14.78%) and S2 (0.71–6.69%) species. The dominant species in Yingmaili terrestrial oils are S1 (51.41–52.76%), O1S1 (26.83–35.27%) and O2S1 (11.97–21.76%) species; no S2 species were detected. The results suggest that the sulfur compounds present in oil vary with the oil type. For the S1 and S2 species, as the thermal maturity increased, the degree of condensation increased, and the median and range of the number of carbon atoms decreased. Compounds with DBE values of 9, which are most likely dibenzothiophenes, became concentrated as the thermal maturity increased. Therefore, the unusually high abundance of dibenzothiophenes in the Lower Ordovician oils could be related to the thermal maturity. The TZ83 (O1) oil has an abnormal distribution of S1 species, and is characterized by sulfur species with relatively low DBE values (0–7). This abnormal distribution could be caused by thermochemical sulfate reduction, and a relatively high content of H2S in the associated gases and abundant sulfo-diamantane in the oil supported this theory. In conclusion, the thermal maturity, organic facies, paleoenvironment of the source rock, and possibly thermochemical sulfate reduction have a large impact on the sulfur compounds present in the oils. The O1S1/S1 and S2/S1 ratios could be used as indicators of the precursors/paleoenvironment, and C10–19/C20–50 DBE9 and DBE1,3,6 /DBE9 could be used as indicators of thermal maturity. Fourier transform ion cyclotron resonance mass spectrometry is very useful for detecting sulfur compounds, especially those with high molecular weights, in the crude oils. This technique has potential for determining the formation mechanisms of some unusual oils and the geochemical implications of the sulfur compounds they contain.

Geochemical Characteristics of Crude Oil and Oil-Source Correlation of the Paleogene “Red Bed” in the South Slope of the Dongying Depression, Bohai Bay Basin, China

The Paleogene Red Bed in the South Slope of the Dongying Depression is a set of red clastic sediments of the lower section of 4th member of the Shahejie Formation and the Kongdian Formation, and is the alternative strata for oil and gas exploration in this area. The Red Bed crude oil of the South Slope of the Dongying Depression is divided into four types according to the assemblage characteristics of biomarkers from 17 oil sand samples and 3 crude oil samples. The Type I crude oil is generated from the source rocks of the lower section of 3rd member of the Shahejie Formation, with low phytane and gammacerane concentration, Ph/ n-C18<0.6, relatively high ratios of Ts/(Ts+Tm) (>0.38) and hopanes/steranes (>3.4), high diasteranes concentration, and low C35 homohopane index. The Type II crude oil could be derived from the source rocks of the upper section of 4th member of the Shahejie Formation with abnormal high phytane and gammacerane concentration, Ph/ n-C181, relatively low ratios of Ts/(Ts+Tm) (<0.38) and hopanes/steranes (<2.5), low diasteranes concentration, and high C35 homohopane index. The Type III crude oil is mixed oil consisting of the Type II crude oil charged in the early stage and the Type I crude oil charged in the late stage and mainly of the Type I crude oil. The Type IV crude oil is characterized by C29 sterane predominance and this feature has not been found in the crude oils and source rocks of the study area, therefore this type of oil is identified as a mixture of the Type II crude oil and an oil type from a shallow lake-swamp facies. The fault throw of oil transporting faults controls the distribution of crude oils with different genetic types, and the upthrown side of the faults is the favorable zone for the Red Bed oil and gas accumulation.

Organic geochemical characteristics of crude oils from the Masila Basin, eastern Yemen

The Masila Basin is an important hydrocarbon province in Yemen, but the origin of hydrocarbons and their generation history are not fully understood. In this regard, 10 crude oils from different petroleum reservoir sections in the Masila Basin were characterized by a variety of biomarker and non-biomarker parameters using GC, GC–MS and stable carbon isotope techniques. Oils from the Masila Basin display pristane/phytane (Pr/Ph) ratios ranging from 1.7 to 2.0, low sulfur content, high C 35 homohopane index, relatively high C 27 sterane concentrations and relatively high tricyclic terpanes suggesting a marine clay source rock that was deposited in mildly anoxic to suboxic conditions with dominantly algal organic matter. C 29 20S/(20S + 20R) steranes and ββ/(ββ + αα) sterane ratios indicate that the Masila oils have reached peak oil window maturity. Another related feature of these oils is the absence of 18α (H)-oleanane, which suggests a source age older than Cretaceous. The carbon isotope compositions are similar to those of the potential source rocks, which range from −25.4‰ to −28.3‰, indicating a marine environment. The new data presented in this paper suggest that the Masila oils constitute one oil family and that the oil originated from the Upper Jurassic Madbi source rock in the basin.

Bulk Geochemical Characteristics of Crude Oils From Wells in the North Western Desert, Egypt

Different oil samples were collected from oil fields in the North Western Desert; namely, Meleiha, Razaak, and North Qarun fields. These oils were analyzed geochemically, including sulfur content, American Petroleum Institute (API) gravity, and gas chromatography The results showed that API gravity and sulfur content indicate that the crude oils have high mature level of marine origin. Distribution of n-alkanes (Carbon Preference Index [CPI], pr/ph, and isoprenoide/n-alkanes ratios) reflects that the oil samples originated mainly from marine organic sources deposited in a reducing environment. This indicates that the oil samples under investigation are well correlated with each other in the western part of the North Western Desert.

A kinetic model of stable carbon isotope ratios in gaseous hydrocarbons generated from thermal cracking of n-tetracosane and its application to the Tarim Basin

Based on quantitative modeling and experimental data on n-tetracosane cracking to generate gaseous hydrocarbons in a confined system, we calculated the generation kinetics and carbon isotope kinetics of methane, ethane and propane and determined the main controlling factors influencing the variation of δ 13C 2 and δ 13C 3. The carbon isotope of gaseous hydrocarbons from n-C 24 cracking to gas are comparable to those from crude oil reported recently, and they can be used to investigate the geochemical characteristics of crude oil cracking to gas under geological conditions. The geological model of n-C 24 cracking suggests it is stable at 150 – 160 °C and its cracking temperature ranges from 180 to 200 °C, consistent with geological models of crude oil cracking currently reported. With increasing degree of thermal stress, the changes in δ 13C 2 and δ 13C 3 are larger than that of δ 13C 1. It is shown that isotope accumulation controlled by the recharging history of a reservoir has a considerable impact on the carbon isotope distribution of natural gas. Compared to that of cumulative gas, the carbon isotope ratio of partly accumulation gas is heavier and influences the fractionation of the δ 13C 2 and δ 13C 3 curves to a greater extent. The geological model of n-C 24 cracking to gas has been used to interpret the origin of carbon isotopic variation of natural gas in some reservoirs in the Tarim Basin.

Geochemical characteristics and genetic types of crude oils from the Tertiary system in the southern part of western Qaidam Basin, Northwest China

Crude oil samples taken from the southern part of western Qaidam Basin were analyzed with GC/MS in order to understand the geochemical characteristics of crude oils. The results reveal that most crude oils are characterized by high abundance of gammacerane and C35 homohopane, which are the representative characteristics of saline lacustrine crude oils. Based on the variation of the ratios of gammacerane/C30 hopane (G/H) and C35 homohopane/C34 homohopane (C35/C34H), two crude oil groups, A and B, are identified. Group-A crude oils mainly occurr in the north of the study area, with higher ratios of G/H (>0.8) and C35/C34H (>1.2), whereas group-B crude oils, selected from the south of the study area, show lower ratios of G/H (<0.8) and C35/C34H (<1.0). In addition, group-A crude oils are distinguished into three subgroups in accordance with their different ratios of G/H and C35/C34H and different distribution characteristics of n-alkanes, isoprenoids and steranes. These may be helpful for understanding the distribution characteristics of crude oils in the southern part of western Qaidam Basin and providing clues to the forthcoming exploration of crude oils and gas.

Geochemical characteristics of crude oils from Well Zheng-1 in the Junggar Basin, Xinjiang, China

Well Zheng-1 is located in the combined area of the central uplift and the north Tianshan piedmont depression in the Junggar Basin. Two oil-bearing beds are recognized at 4788–4797 m of the Lower Cretaceous Tugulu Formation (K1tg) and 4808.5–4812.5 m of the Lower Jurassic Sangonghe Formation (J1s). The geochemical characteristics of family composition, carbon isotopic composition, saturated hydrocarbons, sterane and terpane biomarkers and carotane of two crude oils are described in this paper. The results show that the geochemical characteristics of the two crude oils are basically similar to each other, indicating they were all derived mainly from the high mature, brine, algae-rich lake facies sediments. Oil-source correlation revealed that crude oils of the two beds were derived mainly from the source rocks of Permian and mixed by the oil derived from the source rocks of Jurassic and Triassic. This is consistent with the geological background with several sets of source rocks in the area studied.

Geochemical characteristics of crude oils from the Sagara oil field, Shizuoka Prefecture, Japan

Abstract Six oil samples collected from the Sagara oil field, Shizuoka Prefecture, were geochemically analyzed. Unlike the Niigata oils, the Sagara oils: (i) are low-sulphur light oils dominated by gasoline and kerosene fractions; (ii) have low values of environment index in light hydrocarbon compositions; (iii) have high Pr/n-C17 and low Ph/n-C18 ratios and high oleanane/hopane ratios; (iv) have high relative abundance of C29 and low relative abundance of C28 regular steranes; and (v) have ‘light’ stable carbon isotope compositions. These characteristics show that the source rocks of the Sagara oils contain mainly marine organic matter, but with more input of terrigenous organic matter deposited under more oxic conditions compared to those of the Niigata oils. The light carbon isotope compositions and the low relative abundance of C28 regular steranes of the Sagara oils suggest that their source rock is not Miocene, but probably Paleogene in age. The Sagara oils probably migrated along faults from deeper parts of the basin.

Nitrogen isotopic geochemical characteristics of crude oils in several basins of China

Nitrogen isotopic ratios of crude oils with different physical and chemical properties in several basins of China have been measured and their geochemistry has been studied elementally combined with molecular organic geochemistry methods. The data indicate that d 15N is in the range of -6‰－20‰. They vary with the oils in different sedimentary types of basins. The oils forming in the limnic environment have lower d 15N with the value of about 1‰－5‰ whereas the oils in saline or semi-saline environment have higher d 15N, with most samples being above 10‰ and some exceeding 17‰. The average nitrogen isotopic ratio of oils from the Ordovician forma-tion in the Tarim Basin is the lowest, with most samples having d 15N below zero, which reflects possibly the characteristic of the oils originating mainly from the organic matter formed in marine carbonate sedimentary environment. The d 15N distribution can be altered by fractionation. It increases obviously because of biodegradation and decreases during hydrocarbon migration. However, the effect of nitrogen isotopic fractionation in the short distance migration is uncon-spicuous.

Reservoir geochemistry of the Kuche petroleum system in the Tarim Basin, China

The geochemical characteristics of crude oils and reservoir core extracts from the Kuche petroleum system are described and studied systematically by means of various geochemical techniques and methods to acquire molecular information. The results suggest crude oils from the petroleum system can be divided into two groups: marine oils and non-marine oils. The former represents the dominant oils found in the area. Tar mats were firstly discovered and determined accurately in terrestrial oil and gas reservoirs, with Lower Tertiary sandstone reservoirs in the Yaha oilfield of the Tarim Basin. However, based on the ratio of 20S/ (20S + 20R) C29 sterane as a maturity parameter, lacustrine oils filled into the Tertiary reservoirs in the direction toward the western part of the petroleum system. In contrast, according to the fact that methylcyclohexane indices of eastern oils are greater than those of western oils, the location in which coalgenerated oils filled into the Tertiary reservoirs lies in the eastern part of the petroleum system.

Geochemical characteristics of crude oils from Zao-V oil measures in Shenjiapu oilfield

The geochemical characteristics of crude oils from Zao-V oil measures in the Shenjiapu oilfield are systematically described in terms of the fractional composition of crude oils, GC characteristics of saturated hydrocarbon fraction of crude oils and the characteristics of their bio-markers. The depositional environment, type and evolution of the biological source are also discussed. All pieces of evidence such as low saturated hydrocarbon fraction, high resin and asphalt, high isoprenoid alkane, weak odd-carbon number predominance ( CPI ranging from 1.23 to 1.29, OEP ranging from 1.14 to 1.16) and low sterane and terpane maturity parameters show these crude oils are immature oils. Low Pr/Ph ratios (0.66–0.88) and high gammacerance/C31 hopane ratios (0.59–0. 86) indicate the source rocks were formed in a slightly saline to brackish reducing lake depositional environment. Gas Chromatographic characteristics of the saturated hydrocarbon fraction and the predominance of C30 hopane in terpane series and C29 sterane in sterane series indicate the biological source of the crude oils is composed mainly of bacterial and algal organic matter, and some algae are perhaps the main contributor of organic matter to the source rocks.

Geochemical characteristics of crude oils from the Cuyo Basin, Argentina

Crude oils from the Triassic Cuyo Basin are thought to be derived from a fresh-water lacustrine source rock, mainly the Upper Triassic organic-rich shales of Cacheuta Fm. By means of GC and GC-MS methods, the oils were analysed for characteristic compounds which may reflect biological input to the source sediments and maturity variations. Pristane/phytane ratios, distributions of n-alkanes, and the presence of significant amounts of bacteriohopanoid-derived compounds (hopanes, 8,14-secohopanes, 8,14-monoaromatic secohopanoids, benzohopanes) together with bicyclic sesquiterpanes in all the samples studied, are taken as an indication of possible reworking of algal organic matter by bacteria. Sterane distributions were consistent with a lacustrine origin of the oils. The occurrence of selected alkylnaphthalene derivatives as dominant compounds in the aromatic hydrocarbon fractions was a matter of special attention in the study. The variation of their concentrations with the maturity of the oils is compared to that of monoaromatic 8,14-secohopanoids. The results suggest that 1,2,5-trimethylnaphthalene in these oils is a product of hopanoid degradation under mild thermal conditions.

Geochemical characteristics of crude oils and source beds in different continental facies of four oil-bearing basins, China

Summary In order to correlate Chinese continental crude oils with their sources and, thus, the different depositional facies of the sources, the geochemical characteristics of crude oils and of extracts from related source rocks in four different types of continental facies were studied. The four types of facies were those of (1) inland and paralic freshwater to brackish lake basins, (2) saline lake basins, (3) inland swampy lake and swamp basins, and (4) terrestrial and marine intertonguing facies basins. Oils from these facies show both similarities and differences. Some specific biomarkers, such as the stereoisomers of onocerane, serratane and long chain acyclic polymethylalkanes which could be useful indicators of a palaeoenvironment, are also discussed. All the components were identified using mass spectrometry and a few retention index data: therefore, the identification of some compounds must be tentative.