Geochemical Characteristics Of Crude Oils Research Articles

Geochemical characteristics of crude oils and source rocks in the Malaysia-Thailand Joint Development Area (MTJDA), North Malay Basin

The Malaysia-Thailand Joint Development Area (MTJDA) that located in the North Malay Basin has been investigated in this study to resolve few issues concerning to petroleum potential and resources which has been abandon for decades. Despite Malay Basin having been proven to contain prolific oil and gas resources, the MTJDA which located in the Northern area however contains mainly gas with very minor oil. Thus, this study aimed to investigate the main factor that controls the hydrocarbon generation, type and distribution in this basin. The investigation involves biomarker characterization, thermal maturity assessment of source rock, crude oil and condensate, together with oil-oil and oil-source correlation that has never been established before. The geochemical data as indicated by bitumen extraction, GC-MS and Py-GC analyses on 40 cutting samples and 8 liquid samples (six oil samples and two condensate samples) revealed that the cutting samples were moderate in quality with variable richness based on TOC (total organic carbon) and a variable degree of maturity based on the biomarker proxy parameters of isoprenoid, hopanoid and steroid. The organic matter input for the source rock was derived from a mixed marine-terrestrial and terrestrial source and deposited in fluvial-deltaic/estuarine settings having oxic to sub-oxic depositional conditions. Based on biomarker fingerprints and proxy parameters, the oil and condensate samples were essentially of the same group, originating from a similar source rock, with some facies variation due to variations in organic matter input and degree of maturity. The results also indicated that the crude oil samples were originated from the coaly and carbonaceous shales of Group I, with mixed kerogen of type II/III that could produce gas with minor oil. There is also the possibility that these hydrocarbons were generated from a deeper interval of Group E (higher thermal maturity), deposited in a similar setting as Group I.

Retracted: Geochemical Characteristics of Crude Oil in Member 7 of Yanchang Formation in Yanchang Oilfield

Retracted: Geochemical Characteristics of Crude Oil in Member 7 of Yanchang Formation in Yanchang Oilfield

Chemometric recognition of oil–source in the western the Ordos Basin, China

In recent years, significant breakthroughs in the exploration and development of tight oil in the Lower Triassic Yanchang Formation of the Ordos Basin have been achieved. However, there is still a lack of genetic relationship analysis of oil sources in this basin on a large scale. In this study, we performed Rock–Eval pyrolysis to analyze 41 source rocks in four study areas. A total of 79 crude oil and source rock samples from this region was analyzed using gas chromatography mass spectrometry to identify the geochemical characteristics of crude oil and source rocks. Based on 16 biomarker parameters, we used principal component analysis and multidimensional scaling for the analysis of the crude oil source. Combined with alternating least squares, we quantitatively calculated the contribution rate of source rocks to crude oil. The results indicated that the region can be divided into four types of oil sources: the Habahu area in the northwest of the basin, the Huanxian area in the west of the basin, the Pengyang area in the southwest of the basin, and the center of basin. The oil–source comparison results reveal that the reservoirs in the central basin are of single crude oil, whereas those in the Habahu, Huanxian, and Pengyang areas are mixed crude oil. Based on ALS, the relative contribution rates of source rocks in each area to different samples were determined. The present research provides us with a valuable method to use a variety of chemometrics methods to jointly judge the crude oil source and the classification of gene groups.

Geochemical Characteristics of Crude Oil in Member 7 of Yanchang Formation in Yanchang Oilfield

Oil is an important primary energy for national production and life and national defense, and China is the key to rapid development. It is of great strategic significance to ensure the safe and efficient production of the oil industry. Yanchang Oilfield is located in the main position of oil and gas accumulation in Ordos Basin, China, and the seventh member of the Yanchang Formation is the area with the richest crude oil output at present. Studying the geochemical characteristics of its crude oil exploitation is of great engineering significance for the exploration of oil and gas content in similar terrain and the continuous improvement of oil extraction and refining technology. On the other hand, it also provides first-hand data and important technical references for the exploration and exploitation of oil and gas resources in other areas of the Ordos Basin. Firstly, this paper points out the important strategic significance of the petroleum industry for China’s development, and briefly describes the basic situation of Yanchang Oilfield and the basic characteristics of crude oil. The power and diversion system of the Yanchang Formation in Yanchang Oilfield are studied, and the main factors of formation and flow of deep reservoirs in the Yanchang Formation are explored, as well as the regional geological survey of the Yanchang Formation No. 7 in Yanchang Oilfield. The characteristics of crude oil and its maturity evaluation system are emphatically discussed, and the changes in crude oil characteristics under the action of microorganisms are comparatively studied. In this paper, Yanchang Oilfield, the main reservoir area of the Ordos Basin, is taken as the research object, and the formation mechanism of the oil reservoir and the geochemical characteristics of crude oil in the 7th member of the Yanchang Formation are deeply explored, so as to provide a preliminary theoretical study for the research of crude oil exploitation in reservoirs and other oilfields in the Ordos Basin.

Investigation of the Geochemical Properties and Origin of the Crude Oils Accumulated in the Mishrif Reservoirs in the Zubair, Halfaya, and Buzurgan Oilfields, Southern Iraq

The Mishrif Formation is among southern Iraq's most important reservoirs, which contains a third of the oil in the Cretaceous reservoirs, which is a broad carbonaceous succession in Iraq and the surrounding area. For detecting differences in the geochemical characteristics of crude oil, three crude oil samples were obtained from the Mishrif carbonate reservoir intervals in the Cretaceous at the Zubair, Halfaya and Buzurgan oilfields in southern Iraq. Analyses utilize API gravity, sulfur concentration, Gc, Gc/MS, and bulk carbon isotope compositions. The low API (23 to 28) and high sulfur content (4.45 to 5.36 wt%) of the oils studied can be linked to the deposition of a marine carbonate environment under sulfate-reducing environments. The anoxic, non-biodegradation, organic matter type II-S, marine carbonate depositional was indicated by the pristane/ nC17 (0.16 to 0.26), phytane/ nC18 (0.29 to 0.31), narrow Pr/Ph ratio range from 0.76 to 0.78, high C29/C30 hopane ratios of 1.01–1.71, and low C26/C25 tricyclic terpene ratios in the related source-rock. TAS3 (CR) ratios of 0.33 to 0.36, C27 Ts of 0.18 to 0.22, and 29 sterane 20S/20R sterane ratios all refer to early maturity. Biomarker parameters and bulk carbon isotope values in the oil analysis match those found in the Sulaiy and Yamama sources of the Late Jurassic-Early Cretaceous.

Geochemical characteristics of crude oil in the eastern of Qinnan sag, Bohai Bay Basin, Eastern China

The oil and gas exploration degree of Qinnan sag is low. In this paper, all the 17 crude oil samples from the four reservoirs in the eastern Qinnan sag were taken as the research object. Research methods include GC-MS, stable carbon isotopic of crude oil and group components and other analytical methods. The geochemical characteristics of crude oil were studied by the main parameters, Pr/ph, γ/C31 hopane, Ts/Tm, 4MSI and C29 sterane isomerization. The results show that most of the hydrocarbon generating parent materials of all the 17 crude oils are reductive lacustrine sedimentary organic matter with higher salinity. The crude oil of Es12 is mainly derived from low aquatic algae, and the crude oil of Ed3, Ek and Mz shows the characteristics of a mixed source. The maturation characteristics of crude oils are low mature-mature. The stable carbon isotope of oil and the components is in the range of −30‰ to −26‰, which shows the distribution characteristics of δ13CST <δ13CASP <δ13CNOS <δ13CAR. The characteristics in B-6, C-1 and C-3 of crude oils show the heavy δ13CASP and high abundance of hopane, indicating that there is more contribution from bacterial sources. The crude oil from Es12 is mainly the contribution of Es1 source rocks. The crude oil of Mz, Ek and Ed3 is mainly the mixed source of Es1 and Es3 source rocks, and Es3 is the main source, and the oil source may mainly come from the southeast subsag. The carbon isotope of the component in Block D can be divided into two kinds of crude oil, which may contribute to the oil source of the Bozhong sag. The eastern of Qinnan sag has great hydrocarbon potential.

Geochemical characteristics of crude oils and hydrocarbon accumulation in the Palogue Oilfield, Melut Basin, South Sudan

The Palogue Oilfield is the largest oilfield in the Melut Basin, an important petroliferous rift basin in Africa. Geochemical analyses, including gas chromatography and gas-mass chromatography were adopted to analyze the biomarker composition and geochemical characteristics of oils from the Palogue Oilfield and the neighboring Moleeta and Jamous lows. Oil-oil correlations were performed for the Palogue Oilfield and the Moleeta/Jamous lows, and the hydrocarbon accumulations of the Palogue Oilfield were studied based on the oil maturities, thermal evolution modelling of the Moleeta/Jamous lows and the petroleum system analysis of the Melut Basin. Geochemical analysis indicates that the oils of the Moleeta/Jamous lows are derived from terrestrial higher plants, with the low ratios (<1) of light n-alkanes to heavy n-alkanes (∑nC21-/∑nC22+) and the predominance of C29 regular sterane, but there still are some geochemical differences in distribution shape of n-alkanes, paleoenvironments and maturities in these two lows. The oils of the Palogue Oilfield have mixed-source features and their geochemical characteristics are more like those of the Jamous low, and a few oils are like the oils in the Moleeta low. The Jamous low has a larger area and higher thermal maturity than the Moleeta low, and the abundant oils generated by the Al Renk source rocks (upper part of early Cretaceous) in the Jamous low are the primary contributors to the formation of the giant Palogue Oilfield. The vitrinite reflectance equivalent (Rc) converted by the methyl phenanthrene ratio indicates that the oil maturities of the Palogue Oilfield range from 0.65% to 1.07%. Thermal evolution modelling of the Moleeta/Jamous lows indicates that the Jamous low generated and expelled hydrocarbons earlier than the Moleeta low. The maturity of Al Renk source rocks reached 0.65% at 70Ma (Late Cretaceous) and 1.07% at 38Ma (Eocene) in the Jamous low, and reached 0.65% at 59Ma (Paleocene) and 1.07% at present in the Moleeta low. Thus, the high-maturity oils (Ro> 1.07%) generated by the source rocks in the Jamous low since 38 Ma have not been discovered in the primary production layers of the Paleogene Samma and Yabus Formations in the higher part of the Palogue structure, a drape-anticline developing on a paleo-high between the Jamous and Moleeta lows. The maturity parameter of Ts/(Ts + Tm) shows that the oil maturities from late Cretaceous Formation in the well PS-7 and PS-8 are close to the oils in the Jamous Low and are significantly higher than the oils from the Paleogene Formation in the higher part of the Palogue structure. So, the Cretaceous Formation under the Paleogene pay zones and the Paleogene Formation in the lower part of the Palogue structure likely accumulated high-maturity oils from the Jamous low, which will enhance the exploration potential of the Palogue Oilfield. The petroleum system study indicates that the end of Oligocene (late Paleogene) is the critical moment for the Paleogene hydrocarbon accumulations in the Melut Basin. Whereas, the high-maturity oil accumulations (Ro> 1.07%) in Cretaceous formations in the Palogue Oilfield occurred after 38Ma (late Eocene), when the Al Renk source rocks in the Jamous low started to enter the high thermal evolution stage with the Ro> 1.07%.

Geochemical Analysis of a Multi-Layer Hydrocarbon Reservoir in the Wuerhe Area, Junggar Basin

From 5000 m underground to the surface, there is a multi-layer hydrocarbon reservoir under the Wuerhe nose uplift in the Junggar Basin. Light oil, heavy oil, oil sand, and solid bitumen are found in Permian to Cretaceous strata. The normal crude oil present under heavy oil and solid bitumen reservoir can easily ignored by explorers. To effectively exploit the petroleum and bitumen mineral resources in the Junggar Basin, geochemical characteristics of crude oils in the different layers were analyzed. It is concluded that the crude oils and bitumen minerals came from Permian source rocks of alkaline lacustrine facies. Combined with tectonic movement analysis, two stages of accumulation occurred in research area. During the Indosinian Tectonic movement, the crude oil generated from Permian source rocks first migrated upwards along large faults and then accumulated in the Permian, Triassic, and Jurassic reservoirs. The crude oil of the Jurassic reservoir was seriously biodegraded and a high abundance of 25-norhopane was detected. At the end of the Yanshan movement, small normal faults were developed to connect the oil in the Triassic reservoirs to the surface. The light components of the oil in the fault system quickly volatilized and left solid bitumen minerals in the faults. Due to the plugging effect of “bitumen plug”, the oil and gas in the lower part cannot migrate upward and be damaged. Therefore, light oil-heavy oil–oil sand and bitumen minerals were formed from the bottom to the top. The research result will also have a guiding significance for oil and gas exploration in the northwest margin of the Junggar Basin.

Geochemical characteristics of crude oils and basin modelling of the probable source rocks in the Southern Mesopotamian Basin, South Iraq

Bulk property and geochemical analyses were performed on 15 crude oil samples collected from the Early Cretaceous clastic reservoirs in the oilfields of the southern Mesopotamian Basin, South Iraq. Specific gravities ranging between 25.4 and 31.6 API and relatively high sulfur concentrations of up to 1.97 wt % suggest that the samples were generated from kerogen Type II-S at relatively low maturity level. Biomarker ratios and parameters as well as carbon isotope ratios, indicate that the oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions during the Jurassic to Early Cretaceous. Furthermore, biomarker maturity suggests two maturity subgroups for the samples based on their sulfur concentrations and specific gravity values. Sub-group (A) is characterized by oils generated from low-mature source rocks from the Late Jurassic-Early Cretaceous Sulaiy Formation; while the relatively high mature oils of sub-group (B) were generated from organic-rich intervals in the Jurassic Sargelu and Najmah formations. Basin model results revealed that these formations reached a peak oil-generation window at different times, expelling various quantities of oil. The basin model results further suggest that the organic-rich interval in the Sulaiy Formation began to expel little amounts of oil, corresponding to transformation ratio (TR) between 50 and 63% since the Late Miocene to present-day, while the organic-rich intervals in the Sargelu and Najmah formations were the earliest to expel significant amounts of oil, with relatively high TR values of 50–90% during the end of the Late Cretaceous to Early Eocene and continued to the present-day. These generated oils subsequently migrated to the shallow stratigraphic reservoir intervals through the vertical pathway of faults, and are currently extracted for use in the oil industry.

Geochemical characteristics of crude oil and oil-source correlation in the western Qaidam Basin, China

The Cenozoic in the western Qaidam Basin is rich in oil and gas resources and has good prospects for exploration. The maturity, sedimentary environment, and biological source of the crude oil in the western Qaidam Basin are discussed based on the composition characteristics of biomarkers in crude oil and source rocks. The above is performed to classify the genetic types of crude oil and determine the oil source relationship. It is found that the crude oil shows the characteristics of low mature–mature and is formed in the reducing environment with high salinity. The organic matter is from the mixed source with dominant aquatic plants input. According to the sedimentary environment, parent material types, and maturity characteristics, the crude oil in the western Qaidam Basin can be classified into four types. (1) Type I is from the Shizigou-Yuejin areas, which have a high content of gammacerane, a low value of Pr/Ph, C27 sterane predominance, and “tail-upwarping” phenomenon. (2) Type II is from the Qiekelike-Zhahaquan and Nanyishan-Youquanzi areas, which have C27 sterane predominance and no “tail-upwarping” phenomenon. Its content of gammacerane is lower than type I. (3) Type III is from the Dafengshan and Huangguamao areas, which have C29 sterane predominance and no “tail-upwarping” phenomenon. (4) Type IV is from the Kaitemilike area, which has a C27 sterane predominance, no “tail-upwarping” phenomenon, and lower content of gammacerane than that of others. The result of the oil-source correlation shows that the crude oil is dominantly derived from source rocks of the lower Ganchaigou Formation (E3) and the upper Ganchaigou Formation (N1).

Analysis of tight oil and gas charging characteristics by the carbon isotope on-site detection technology: A case study of the northern slope of the Minfeng Subsag in the Bohai Bay Basin

Studying hydrocarbon charging is quite important for searching exploration targets and confirming well locations. In this paper, the north slope of the Minfeng sub-sag in the Bohai Bay Basin was taken as an example. The Wells Yanxie 233, Yongxie 932 and Yan 22 were selected for on-site carbon isotope detection. Then, based on sufficient carbon isotope data which were acquired on the drilling site using the brand-new carbon isotopic measuring instrument, the carbon isotope data and composition data of natural gas produced in this area were compared. And combined with the evolution of source rocks, the geochemical characteristics of crude oil, the depositional environment of reservoirs and the physical properties, single-well charging characteristics and regional charging area of natural gas were analyzed. Finally, the feasibility of on-site carbon isotope detection method to discriminate hydrocarbon charging was discussed. And the following research results were obtained. First, deep hydrocarbon charging happened in the Purely Purely Lower Sha 4 Member in Well Yanxie 233, and its natural gas is the mixture of the oil cracking gas of deep layers and the thermal cracking gas of autochthonous source rocks. Second, the natural gas in the third and fourth Members of Shahejie Formation in Well Yongxie 932 is the thermal cracking gas of autochthonous source rocks, but deep gas charging occurred in particular hole sections. Third, the carbon isotope of associated gas in Well block Yan 22 is high in the central area and low in both sides and high in the south and low in the north, which is accordant with the distribution characteristics of reservoir physical properties, indicating that the charging of high-maturity natural gas is under the control of reservoir physical properties. Fourth, the oil in Well block Yan 22 is the product of autochthonous source rocks in the mature stage while the natural gas is the autochthonous oil-associated gas combined with the charging of deep high-maturity product. It is concluded that there is a high-maturity hydrocarbon charging area in the northwest of the northern slope of the Minfeng sub-sag, and it is a favorable hydrocarbon exploration target. What's more, the on-site carbon isotope rapid detection technology can provide a large number of continuous three-dimensional carbon isotope data, and it can be used to quickly analyze the characteristics of hydrocarbon charging and determine the source and origin of hydrocarbon, so as to provide reference for hydrocarbon development deployment.

Geochemical characteristics of crude oil in the continental saline lake basin: a case study of the Upper Part of the Lower Ganchaigou Formation in Yingxi, Qaidam Basin, China

The crude oil in the Upper Part of the Lower Ganchaigou Formation in the Yingxi area of the Qaidam Basin, China, was formed in a strongly reducing and high-salinity sedimentary environment with algae as the main parental material. The crude oil in this area possesses the typical geochemical characteristics of saline lacustrine crude oil. The crude oil is mainly derived from source rocks of its own horizon, indicating that the reservoirs in the study area have self-generation and self-storage reservoir features.

Typical end-member oil derived from Cambrian-Lower Ordovician source rocks in the Tarim Basin, NW China

Abstract Based on GC-MS data of saturate and aromatic hydrocarbon fractions in crude oils from Well TD 2 and the Yingmaili and Tazhong area in the Tarim Basin, the end-member oil derived from Cambrian-Lower Ordovician source rocks was determined. The analytical results show that the crude oil from Well TD2 is rich in 3-6 ring polycyclic aromatic hydrocarbons without alkyl group, suggesting that this oil was altered by an abnormally thermal event. It contains a complete series of normal alkanes and 25-norhopanes, indicating that it is mixed oil of normal oil and biodegraded oil, so it can't be taken as end-member oil derived from Cambrian source rocks. The geochemical characteristics of crude oils from Well TZ11 and TZ30 are completely different from the crude oils from Well YM101 and YM201 generated by Middle–Upper Ordovician source rocks, so it is inferred that they are derived from Cambrian-Lower Ordovician source rocks. In addition, these crude oils don't contain 25-norhopanne series, indicating that they haven't suffered biodegradation and satisfy with geochemical conditions of end-member oil. It is noteworthy that the two kinds of marine oils have similar triaromatic steroids and methyl triaromatic steroids, but very different C27-29 steranes and C28-30 methyl steranes, showing that they are not a good indicator of organic matter input. Triaromatic dinosteroids are a kind of biomarkers most usually used in marine oil-source correlation in the Tarim Basin, but the big differences in their relative abundances between crude oil from Well TD 2 and two kinds of end-member marine oils suggest that they are easily affected by thermal maturity and should be cautiously used in marine oil-source correlation.

Advanced Aspects of Crude Oils Correlating Data of Classical Biomarkers and Mass Spectrometry Petroleomics

The complex geochemical characteristics of crude oils can provide important information on oil generation, such as the input of organic matter and their depositional environments, also supporting exploration, extraction, and production. This work reports the first organic geochemical evaluation of oils from the first commercial Brazilian onshore field (Carmopolis, Sergipe, Brazil) via both classical biomarkers and petroleomics data collected via ultrahigh-resolution and accuracy Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS). Gas chromatography/mass spectrometry (GC/MS) was used to characterize the oil composition in terms of n-alkane, isoprenoid, terpane, and sterane biomarkers, whereas either positive or negative electrospray ionization (ESI) and FT-ICR were used to profile the polar constituents of the oils. GC/MS revealed geochemical characteristics that classify the oil at different levels of thermal evolution and biodegradation. FT-ICR MS attributed molecular formulas to mor...

Geochemical Characteristics and Origins of the Crude Oil of Triassic Yanchang Formation in Southwestern Yishan Slope, Ordos Basin.

Biomarker compounds that derived from early living organisms play an important role in oil and gas geochemistry and exploration since they can record the diagenetic evolution of the parent materials of crude oil and reflect the organic geochemical characteristics of crude oil and source rocks. To offer scientific basis for oil exploration and exploitation for study area, gas chromatography-mass spectrometry method is applied to study the biomarker compounds of crude oil in Southwestern Yishan Slope of Ordos Basin, through qualitatively and quantitatively analyzing separated materials. The crude oil of Yanchang Formation and the source rocks of Yan'an and Yanchang Formation were collected in order to systematically analyze the characteristics of the biomarker compounds in saturated hydrocarbon fractions and clarify the organic geochemical characteristics of crude oil. The distribution and composition of various types of hydrocarbon biomarker compounds in crude oil suggest that the parent materials of crude oil are composed of hydrobiont and terrigenous plants, and the crude oil is mature oil which is formed in the weak reducing fresh water environment. Oil source correlation results show that the crude oil of Yanchang Formation in Yishan Slope is sourced from the source rocks of Chang 7 subformation.

Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar sag, Junggar Basin

Jimusar sag, which lies in the Junggar Basin, is an important tight oil study area in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oil samples from the Lucaogou Formation were collected for analysis, including physical properties (density and viscosity), bulk composition, saturated hydrocarbon gas chromatography–mass spectrometry, and calculation of various biomarker parameters. Source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. To analyze the hydrocarbon generation history of the Lucaogou source rocks, one-dimensional basin modeling was performed. The oil-filling history was also investigated by means of basin modeling and microthermometry. Biomarkers of suitable source rocks (total organic carbon content is >1%, summation of the free and volatile hydrocarbon and remaining hydrocarbon generative potential is >6 mg HC/g rock, and vitrinite reflectance is between 0.7% and 1%) were analyzed for oil–source correlation. The results indicate that low-maturity to mature crude oils originated from the source rocks containing terrigenous organic matter, which were deposited in a saline lake. The source rocks are of mainly type II kerogen. Oil in the lower section of the Lucaogou Formation is relatively dense and viscous and has elevated nonhydrocarbon content. In addition, a higher proportion of bacteria and algae is shown to have contributed to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil–source correlations demonstrate that not all mudstones within the Lucaogou Formation contribute to oil accumulation. Thin section observation indicates organic macerals surround the grains of some siltstones within the porous and permeable subsections, which proves the siltstones contribute to hydrocarbon generation. Crude oils from the upper and lower sections mainly originate from thin-bedded mudstones interbedded and siltstones within the porous and permeable subsections. The mudstones over or beneath the porous and permeable subsections consist of seals and prevent the vertical movement of oil by capillary forces. Despite being thicker, mudstones between the two porous and permeable subsections make no obvious contribution to the oil accumulation because of their low permeability and distance from the porous and permeable subsections, which is consistent with the principle of near-source charging for tight oil accumulations. Lucaogou oil has been charged twice, once from 235 to 210 Ma and again from 180 to 150 Ma, coinciding with oil generation time.

Effect of magmatic hydrothermal on gas reservoir formation in Permian-Lower Triassic source rocks in Huangqiao Area, South China

The main source rocks for gas reservoirs in Huangqiao area of Lower Yangtze region in south China are Permian-Lower Triassic marine strata with high maturity, including carbonate and clastic rocks. A series of geochemical experiments have been carried out in order to reveal the forming mechanism of large gas reservoirs. Geochemical characteristics of crude oils show the source kitchen, which contributes to the large gas reservoir formation, has changed from kerogen cracking to oil cracking. Based on the results of geological evidences, abnormal distribution of vitrinite reflectance, and fluid inclusion characteristics, magmatic hydrothermal is believed to be existed in Huangqiao area. The magmatic hydrothermal changes the source kitchen in two ways. First, the source rock evolution is accelerated by thermal provided by magmatic hydrothermal. Second, it provides hydrogen in the water contained in magmatic hydrothermal to improve liquid hydrocarbons transforming into gases. Thus, the magmatic hydrothermal might considered to be an important factor forming large-scale gas reservoirs in South China.

Analyzing crude oils from the Junggar Basin (NW China) using comprehensive two-dimensional gas chromatography coupled with time-of-flight mass spectrometry (GC×GC-TOFMS)

As a new technology of analyzing crude oils, comprehensive two-dimensional gas chromatography coupled with time-of-flight mass spectrometry (GC×GC-TOFMS) has received much research attention. Here we present a case study in the Junggar Basin of NW China. Results show that the hydrocarbons, including saturates and aromatics, were all well-separated without large co-elution, which cannot be realized by conventional one-dimensional GC–MS. The GC×GC technique is especially effective for analyzing aromatics and low-to-middle-molecular-weight hydrocarbons, such as diamondoids. The geochemical characteristics of crude oils in the study area were investigated through geochemical parameters extracted by GC×GC-TOFMS, improving upon the understanding obtained by GC–MS. Thus, the work here represents a new successful application of GC×GC-TOFMS, showing its broad usefulness in petroleum geochemistry.

Geochemical Characteristics of Crude Oils From Ras Gharib Oilfields in the Central Gulf of Suez, Egypt

Four representative oil samples have been collected from productive wells, namely: Gharib-164, Gharib-163, Gharib-106, and Gharib-116, scattered within the Ras Gharib oilfield located in the central Gulf of Suez. Their chemical composition, API gravity, sulfur content, and asphaltene content were determined. Saturated hydrocarbon fractions were subjected to gas chromatography. Terpanes and steranes biomarkers have been determined using gas chromatography-mass spectroscopy in order to characterize the type of organo-facies, oil classes, depositional environments, and to assess the thermal maturity level for oil generation. The results showed that the studied oils are belonging to normal oil classes with no heavy biodegradation. It has been found that mature oils are generated from marine shales and carbonates are enriched in marine algae with contributions from terrestrial organic matters. Biomarker analyses suggest that the crude oils are more mature and sources are derived mainly from mixed organic sources from terrestrial and marine inputs contribution to the biomass from algae and plankton in different saline environments.

Petroleum genetic types and oil–gas sources of deep reservoirs in Baxian Depression, Northeast China

Abstract Deep oil and gas resources are increasingly becoming more important as the exploration potential of shallow resources faces ever growing challenges after many years of research and production. The discovery of Well Niudong 1, with a high production rate of 642.9 m 3 /d of oil and 56.3×10 4 m 3 /d of gas, is the deepest reservoir (over 6000 m in depth) found in East China. In order to fully understand the genetic types and probable origins of these crude oils with deep burial depth from Well Niudong 1 and 4 other adjacent deep wells (Wenan 1, Wengu 3, Xinglong 1 and Xinjia 4) in Baxian Depression, a variety of biomarker and non-biomarker parameters were discussed using gas chromatography (GC), gas chromatography-mass spectrometry (GC–MS) and stable carbon isotope techniques. In addition, over 100 samples from potential source rock candidates were submitted for detailed geochemical analysis. Thus, enormous geochemical parameters, referring to maturity, organic matter type and environmental facies, such as n -alkanes, steranes and hopances, were obtained. Deep crude oils from Baxian Depression display pristan/phytane (Pr/Ph) ratios from 2.06 to 3.35 and low sulfur content. Based on the relationship between δ 13 C 1 and C 1 /C 2+3 , gas from Niudong 1 and Wengu 3 Wells are both condensate-associated gases and the gas from Well Xinglong 1 is oil-associated gas. The geochemical parameters show that source rocks from Es 3 and Es 4 formations are deposited in weak reducing and slight oxic environment, the water body is brackish and relatively clean, respectively, the maturity of Es 3 source rocks are from low mature to mature, while that of Es 4 is from mature to high mature. Geochemical characteristics of crude oils with deep burial depth show some similarities to those obtained by the analyses of the Es 4 source rocks in terms of thermal maturity, organic matter input and facies. Therefore, we suggest that the Es 4 has acted as the most probable source rock candidate for generating these oils. With the great thickness and wide distribution of Es 4 in Baxian Depression, an enormous potentiality of deep oil and gas exploration in this area is expected.