Oil-source Correlation Research Articles

2α-Methylhopane: Indicator for Oil–Source Correlation in the Pearl River Mouth Basin, China

Oil samples collected from the Pearl River Mouth Basin (PRMB) were analyzed using comprehensive two-dimensional gas chromatography coupled with time-of-flight mass spectrometry (GC × GC-TOFMS). High abundances of compounds in the 2α-methylhopane series were observed and accurately quantified. Although the 2α-methylhopane series can be a prominent biomarker in the oil and source rock samples, it has generally been used less than non-methylated hopanes. In this study, the 2α-MHI [C312α-methylhopane × 100/(C312α-methylhopane + C30-αβ-hopane) (%)] ranges from 0.81 to 5.77% and 9.06 to 23.93% in Enping Formation- and Wenchang Formation-derived oils, respectively. The high abundance of the 2α-methylhopane series in Wenchang Formation-derived oils is attributed to anoxygenic phototrophs. The relevant 2α-methylhopane parameters showed correlations with C30-4-methyl steranes/∑C29 steranes, Pr/Ph and bicadinane-T/C30-αβ-hopane. Furthermore, the 2α-methylhopane series are rich in middle-deep lacustrine environments as well as marine sedimentary environment. The results indicated that the 2α-methylhopane series could be used as effective biomarkers to distinguish oils derived from different source rocks, as well as to enlarge the PRMB biomarker assemblages, which is beneficial to the evaluation of petroleum resources.

Geochemical characterization of Lucaogou Formation and its correlation of tight oil accumulation in Jimsar Sag of Junggar Basin, Northwestern China

With the constant consumption of conventional oil and gas resources, unconventional oil and gas resources with great resource potential such as tight oil have gradually been valued and become the new exploration area. Jimsar Sag is the key tight oil exploration and development block in Junggar Basin of Northwestern China. Based on the data sets of geology, oil production test, logging, rock thin section, and geochemistry of Permian Lucaogou Formation (LCG), we studied the geochemical characteristics of hydrocarbon source rocks and their relation to the tight oil accumulation. Organic matter abundance of source rocks is high, the types of organic matter are mainly type I and type II, and the organic matter maturation is in the low mature stage to mature stage. Results of oil source correlation showed that the crude oil of sweet spots was mainly derived from the source rocks in the interior of the sweet spots. The LCG tight oil is mainly distributed in the plane where the source rocks have great thickness and the TOC is higher than 3.5%. It shows that the source rocks have obvious controlling on the occurrence and accumulation of tight oil.

Distribution, controlling factors, and oil-source correlation of biodegraded oils in the Bohai offshore area, Bohai Bay basin, China

The vast majority of discovered oils in the Bohai offshore area have undergone biodegradation varying from 1 to 9 on the PM scale (a scale to rank the level of biodegradation proposed by Peters and Moldowan, 1993). The distribution and biodegradation extent of all discovered oils in the Bohai offshore area were investigated systematically using geologic and geochemical data to reveal controlling factors of varying levels of biodegraded oils. Based on the analysis on environment and maternal significances and the resistance to degradation of biomarkers, the biomarker parameter assemblage that is suitable for the oil-source correlation of severely biodegraded oils (higher than PM 6) in the Bohai offshore area was determined. Spatial distribution and biodegradation extent are mainly controlled by current burial depth, the duration of biodegradation, the area of the oil-water-contact (OWC) and a late strike-slip movement of the Tanlu fault. Almost all biodegraded oils are found in shallow reservoirs above 2000 m. The longer the oils are present in these reservoirs or the larger the area of OWC the reservoirs show, the greater the extent of biodegradation will be. The late strong strike-slip movement of the Tanlu fault may have significantly enhanced the biodegradation extent of several oils in fields located in the Tanlu fault zone by introducing oxygenated freshwater from the surface or near-surface and creating a more suitable environment for biodegradation. C19 tricyclic terpane/C23 tricyclic terpane (C19/C23 TT), C24 tetracyclic/C26 tricyclic terpane (C24 Tet/C26 TT) and Gammacerane/C24 Tetracyclic (Gam/C24 Tet) do not seem to be influenced by biodegradation and show obvious differences between the three different source rock intervals. Such a biomarker parameter assemblage can be used successfully to determined the origin of severely biodegraded oils (higher than PM 6) by correlating with extracts of possible source rocks in the Bohai offshore area.

The lower part of the first member of the Shahejie formation (Es1x) as a source rock for oil found in Lixian Slope, Raoyang Sag, Bohai Bay Basin, Northern China

The Es1x sub-member (lower part of the first member of Shahejie Formation), which consists mainly of dark oil shale and mudstone, is well developed in Lixian Slope, Raoyang Sag, Bohai Bay Basin, northern China. The samples from Es1x sub-member were subjected to kerogen petrographic microscope, Rock-Eval, extractable organic material (EOM), and vitrinite reflectance (R o) analyses, respectively. In addition, some samples respectively from the Es3x and Es1x source rocks as well as six crude oil samples from Shahejie Formation of Lixian Slope were subjected to gas chromatography–mass spectrometry (GC–MS) analyses. Based on these geochemical analyses and petrographic analyses, this study provides an overview on the type, richness, thermal maturity, and hydrocarbon generation potential of organic matter in Es1x sub-member, as well as a successful oil–source correlation in Lixian Slope. The total organic carbon (TOC) content of Es1x sub-member samples varies from 0.07 to 6.20%, suggesting that this interval is heterogeneous but contains excellent source rocks. This is further corroborated by hydrocarbon yields (S 2) and extractable organic matter (EOM). Both maceral composition and HI values indicate that organic matter is mostly derived from aquatic organisms. This is supported by n-alkane-isoprenoid ratios (pristane/n-C17 alkane (Pr/n-C17) versus phytane/n-C18 alkane (Ph/n-C18)). The microscope of kerogen in Es1x sub-member samples shows that the mixed-type I/III kerogen is dominant. This is supported by the hydrogen index (HI) values of Es1x sub-member samples. Vitrinite reflectance (R o) values of Es1x source rock samples are between 0.32 and 0.97%, with most of them being lower than 0.7% indicating immature to low maturity levels. T max and production index (PI) values are in line with R o value-based maturity assignments. The n-alkanes and biomarker distributions in crude oils and Es1x source rock samples indicate presence of low-maturity oils derived from organic matter most likely deposited under anoxic, strongly reducing conditions in a lacustrine, brackish to saline/hypersaline water environment. This similarity suggests that crude oils of the Lixian Slope were predominantly sourced from the Es1x sub-member. Es3x (lower part of the third member of Shahejie Formation) source rock samples exhibit different properties that are more in line with freshwater depositional environments.

Overpressure water zone influence on hydrocarbon migration and oil reservoir distribution in low Cretaceous formations of Yinger sag, China

ABSTRACTThe low Cretaceous Zhonggou, Xiagou, and Chijinpu formations are major source rocks in Yinger sag, Jiudong Basin, China. Oil reservoirs were discovered in Zhonggou and Chijinpu formation, which were on the top and bottom of overpressure water zone, but no hydrocarbon was discovered within overpressure zone. The impact of overpressure zone on oil accumulation was indicated by reservoir fluorescence and oil-source correlation study through geochemical analysis. The result shows the overpressure zone reservoirs have less fluorescence display and reservoir extracts dissimilar to source rocks of Chijinpu or Zhonggou formation, implying the inexistence of oil migration in overpressure zone.

Biodegradation characteristics of heavy oil and correlation with group composition and carbon isotopes

ABSTRACTShallow heavy oil is abundant but seriously biodegraded in Chepaizi Uplift and many biomarkers cannot be used effectively. Therefore, some new parameters and methods are used to analyze the biodegradation extent, classification, and oil–source of heavy oil samples. The acid value and group compositions are used to evaluate the biodegradation extent. Carbon isotopes are not only used to calculate the percentage of complex combined oil, but also to correlate oil–source in Chepaizi Uplift. δ13C of oil is used together with biomarkers that can bear serious degradation, such as pregnanes, tricyclic terpanes, and gammacerane. The crossplots of δ13C and biomarkers are effective correlation tools, such as the crossplot of δ13C and C21/C23 tricyclic terpanes. δ13C in different group compositions also show excellent oil–source correlation results. These methods to study biodegraded heavy oil are not only helpful to clarify the biodegradation extent of shallow heavy oil in an extensive area, but also effective to classify heavy oil and correlate oil–source.

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.

Deep-Buried Triassic Oil-Source Correlation in the Central Junggar Basin, NW China

Whether there is an effective deep-buried lacustrine Triassic petroleum system in the Junggar Basin, NW China, has been enigmatic and debated for a long time. Here we conduct an oil-source correlation to address this issue. Results show that the extracted bitumens from the Triassic mudstones in the central basin have distinctive stable carbon isotope and biomarker compositions compared to the Permian-sourced and Jurassic-sourced hydrocarbons, the other two recognized sources in the study area. These characteristics include δ13C value of -30.46~-26.30‰, β-carotane/maximum n-alkane of 0.22–0.41, Pr/Ph of 1.00–1.51, C24 tetracyclic terpane/C26 tricyclic terpane of 0.43–0.96, Ts/Tm of 0.34–0.64, gammacerane/C30 hopane of 0.10–0.14, and regular steranes C27 > C28 < C29 with C29 sterane in dominance (40–50%). These suggest that the Triassic mudstones in the study area host fresh lacustrine organic matters with high input of higher plants. The Triassic-reservoired crude oils and extracts can be divided into two types. Through oil-source correlation, we infer that both type A and type B oils are derived from mixed Permian and Triassic source rocks. Linear regression analysis shows that the contribution from Triassic mudstones to type A and B oils is 67% and 31%, respectively. This implies that the deep-buried Triassic lacustrine mudstones in the Junggar Basin may have some oil-generation potential and thus might represent a new case of Triassic petroleum systems in China and deserves a more detailed and thorough study in future exploration and exploitation.

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.

Hydrocarbon generating potential and accumulation contribution of the fourth member of the Shahejie Formation in the Liaodong Bay sub-basin, Bohai Bay basin

The Liaodong Bay sub-basin is one of the most petroliferous sub-basins in the Bohai Bay basin. The fourth member of the Eocene Shahejie Formation (E2s4, 50.5–42 Ma) which is an important source rock interval in other sub-basins was rarely studied in the Liaodong Bay sub-basin. The hydrocarbon generating potential, biomarker assemblage and accumulation contribution for discovered oil fields of the E2s4 source rock interval in the Liaodong Bay sub-basin were studied using geological and geochemical data. The E2s4 source rocks in the Liaodong Bay sub-basin display relatively high total organic carbon contents (TOC) and Rock-Eval hydrogen indices (HI) and can be considered as a set of excellent oil-prone tendency source rocks. The source rocks interval is characterized mainly by relatively low Pristane/Phytane (Pr/Ph), C19/C23 tricyclic terpane (C19/C23 TT), C24 tetracyclic terpane/C26 tricyclic terpane (C24 Tet/C26 TT), low to medium hopane/sterane (H/S), medium 4-methyl steranes/ΣC29 steranes ratio (4-MS/ΣC29 ST), C35 22S/C34 22S hopane (C35/C34 SH) and high gammacerane/αβC30 hopane (G/H), extended tricyclic terpane ratio [ETR=(C28 TT + C29 TT)/(C28 TT + C29 TT + Ts)] and were deposited in anoxic to sub-oxic saline-water environment with no or minor terrigenous organic matter and medium dinoflagellate input. The maturity of E2s4 source rocks in the Liaozhong and north Liaoxi sags is too high to provide oils for fields. The E2s4 source rocks in the south and middle Liaoxi sag displayed opportune maturity within the oil window and were proved by oil-source correlation having important accumulation contribution for discovered oil fields in this area. The E2s4-derived oils should be taken seriously in the future exploration in the south and middle Liaoxi sag and on adjacent uplifts.

Overpressure characteristics and effects on hydrocarbon distribution in the Bonan Sag, Bohai Bay Basin, China

Overpressure is widespread in the Bonan Sag of the Bohai Bay Basin, East China, and has a strong influence on the migration and accumulation of hydrocarbons sourced from the Es3 and Es4 formations. Pressure measurements in drill stem tests and estimates from sonic logs yield overpressures among different reservoirs and mudstone beds. The fluid pressure in the Bonan Sag increases with depth and is divided into the upper, middle and lower overpressure units that correspond to the Es1, Es3 and Es4 formations, respectively. Oil–source correlation suggests that the distribution of hydrocarbons generated from Es3 and Es4 is controlled by the three pressure units. Hydrocarbons generated from Es4 source rock may laterally migrate within sandstones and accumulate in reservoirs in the Es4 Formation due to the gypsum seal in the lower overpressure unit. A small amount of hydrocarbons vertically migrated along active faults into a shallow formation during charging. However, the effects from faults were more significant on the migration and accumulation of hydrocarbons from the Es3 shale source in the middle overpressure unit. Hydrocarbons generated from the Es3 source rock can vertically migrate into the Es2 or Es1 reservoirs; however, most of them accumulated in Es3 reservoirs. Therefore, the exploration interval should be within the middle and lower overpressure units in the Bonan Sag or along the active fault within the upper overpressure unit.

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

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

Study on oil–source correlation by analyzing organic geochemistry characteristics: a case study of the Upper Triassic Yanchang Formation in the south of Ordos Basin, China

In the south of the Ordos Basin, the oil source of the Upper Triassic Yanchang Formation is confused all the time, which affects further exploration. In this study, oil sources from the oil layers of Ch6, Ch8 and Ch9 are all analyzed and confirmed. Through their carbon isotope value and biomarkers, characteristics of crude oils from the Yanchang Formation are analyzed. Then, the oil–source relation is discussed, with the source rocks’ features. Finally, the oil–source relation is calculated through cluster analysis. It is believed that the oils from the Yanchang Formation deposit in a similar redox environment, with weak oxidation–weak reduction, and have all entered maturity stage. Ch9 crude oil is more mature than crude oils from Ch6 and Ch8, and has more advanced plants and fewer algae. Gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) analysis show that crude oils from Ch6 and Ch8 may come from Ch7, and Ch9 crude oil may not. Cluster analysis displays that crude oils from Ch6 and Ch8 have closer squared Euclidean distance with Ch7 source rocks than Ch9 crude oil does, indicating crude oils from Ch6 and Ch8 stem from Ch7 source rocks. And Ch9 crude oil has rather close squared Euclidean distance with Ch9 source rocks, illustrating Ch9 crude oil may be from Ch9 source rocks. This research may provide the theoretical basis for the next exploration deploy in the south of Ordos Basin.

Influence of thermal maturity on carbon isotopic composition of individual aromatic hydrocarbons during anhydrous closed-system pyrolysis

Anhydrous closed-system pyrolysis experiments were conducted on the pure alkyl naphthalenes, n-alkanes and three crude oils at the highly to over mature stage in order to investigate compositional and isotopic changes of individual aromatic hydrocarbons during laboratory maturation. On the whole, aromatic hydrocarbons have better thermal stability than n-alkanes. While the carbon isotopic composition of substituted aromatic hydrocarbons exhibits a positive correlation with increasing thermal maturity, there is no significant fractionation in the carbon isotopic composition of unsubstituted aromatic hydrocarbons. This finding suggests that the carbon isotopic distribution of unsubstituted aromatic hydrocarbons can be used as an effective tool for oil-oil and oil-source correlation, especially for highly-over mature fields.

Oil-source correlation in Qingdong sag of Bohai Bay basin, China

ABSTRACTGeochemical experiments on 11 cores and 14 crude oil/oil sand samples from Qingdong sag have been performed. The oils range from immature to mature and some of the oils suffered biodegradation. The Es3l member of the Shahejie Formation (group A) deposits under fresh water. The Es4u member (group B) mainly deposits in brackish-saline evaporate environment, generating both immature and mature oils. Results show the nonbiodegraded oils in Es3l reservoirs in the north of the sag (group I) come from mature Es3l member (group A), while those in Es4u reservoirs (group III) come from mature Es3l (group A) and Es4u (group B1) members in the north; the less biodegraded oils (group II) in the western slope are the admixture of immature and mature oils of Es4u member (group B2) in the north; immature oils (group V) in the south are from the neighboring low mature Es4u member (group B3), and the most severely biodegraded oils (group IV) in the southern come from Dongying sag, except oils from well QD-8 that have a contribution from Es4u member (group B3) from Qingdong sag.

Source-rock potential of the lowest coal seams of the Marcelina Formation at the Paso Diablo mine in the Venezuelan Guasare Basin: Evidence for the correlation of Amana oils with these Paleocene coals

The aims of this work were to carry out a combined petrographic, palynofacies, and organic geochemical study of twelve drill-core samples collected from the lowest coal seams in the Paleocene Marcelina Formation (Paso Diablo mine, Guasare Basin, northwestern Venezuela), to characterize crude oil samples from three wells in the nearby Amana Field and to evaluate oil-source correlations of these crude oils with the Paso Diablo coal extracts. The coals under study were classified as high volatile bituminous A or at the B-A boundary, and showed vitrinite contents between 50.0 and 89.4vol.%, liptinites ranging from 1.4 to 24.2vol.%, and inertinites in the 6.2–30.8vol.% range. Results from organic geochemical investigations indicate that the Guasare coals were generated in a limno-telmatic to telmatic zone under fluctuating oxygen conditions. A Type III kerogen with relatively high hydrogen content and a thermal maturity corresponding to the early oil window are proposed for these coals as supported by Rock-Eval and petrographic data, as well as biomarker interpretations. Oil generation potential from Marcelina Formation coals is probably due to the perhydrous nature of the vitrinite, high bitumen contents, and considerable liptinite concentrations, mainly oil-prone resinites and exsudatinites. Palynofacies observations denote a dominance of psilate pollen grains related to angiosperm plants and, as expected, Type III kerogens or humic coals in the studied seams, the parent material of which contained a significant contribution of algae. The non-detection of 18α(H)-oleanane does not preclude the fact that angiosperms are the dominant plants in the Guasare paleomire. On the other hand, the characterization of the Amana oils suggests that they all fall into a unique oil family; the presence of 25-norhopanes in them could indicate paleobiodegradation and mixing from various hydrocarbon charges in the reservoir. Thus, the crude oils from the Amana Field seem to be a mixture of one or more oil charges from the early mature marine carbonate source rocks of the La Luna Formation, deposited under anoxic reducing conditions, and a later pulse of hydrocarbon generation which originated from an unknown – so far – nonmarine source rock. In this regard, hydrocarbon liquid derived from the lowest Marcelina coal seams may be tentatively identified as the latter oil charge. Also, this work delineates some components of a currently subcommercial and hypothetical Tertiary petroleum system – identified and named as Marcelina/Misoa C5(.) – in the Lake Maracaibo region. Finally, the coalbed gas contents of sampled coals were determined.

Forensic characterization of mid-range petroleum distillates using light biomarkers

ABSTRACTDue to oil refining, commonly used higher boiling biomarkers for oil-source correlation are absent from mid-range petroleum distillates, while lighter biomarkers are concentrated in such products. This study evaluated 63 diagnostic ratios of light biomarkers such as bicyclic sesquiterpanes, diamondoids, and lighter aromatic compounds using 70 diesel oil samples obtained from three Swedish refineries and local gas stations, mostly over a six-month period in 2015. On the basis of their diagnostic power and partial correlation coefficients, a set of 24 ratios is suggested for oil-source correlation of lighter products. The frequency of false positives for this set was determined to be approximately 0.1%. It should be emphasized that in the event of an oil spill, diesel oils are rapidly influenced by weathering and many of the ratios will be affected.

Characteristics of complex oil and oil-source correlations in heavy oil regions on the Northern Luxi uplift

ABSTRACTMany biomarkers are not suitable for complex types of oil at different biodegradation extent, especially multisource heavy oil in many regions. On the southern slope near Luxi Uplift, most oilfields are heavy oil regions while some are mixed heavy and light oil regions. Therefore, some parameters that can better show oil characteristics are needed to correlate complex oil and source. Many biomarkers and parameters, such as isoprene, gammacerane, Ts, Tm, diasterane, oleanane, C30hopane, C29sterane20S/20(R+S), and C29steraneββ/(αα+ββ), are taken into consideration. It is found that some combinations and diagrams of some parameters have better oil-source correlation results, such as the Triangular chart of C29S/S+R, C29β/(β+α) and Ts/Tm, the cross plot of gammacerane/C30hopane and Pr/Ph, the plot of C29S/S+R and Ts/Tm, the plot of Ts/Tm and gammacerane/C30hopane, and the plot of C29S/S+R and C29ββ/(ββ+ααα). Through correlations of oil and source, the oil is classified into three types, and the sources of oil in different areas are found. The oil in Boxing sag is mainly from Es3 and Es4 layers. The oil in Chunhua oilfield is mainly from Es4. The oils in Lean, Bamian, and Wang areas are found to be derived from Es4 oil source layers in Niuzhuang Sag. To clarify oil characteristics and oil source is meaningful to compare and find the distribution of better oil types.

Hydrocarbon sources and charge history in the Southern Slope Region, Kuqa Foreland Basin, northwestern China

Numerous oil and condensate gas reservoirs have recently been discovered in the Southern Slope Region of the Kuqa Foreland Basin in the northern Tarim Basin, northwestern China. However, their hydrocarbon sources and charge history are still unclear. In this study, oil-source correlation was firstly used to ascertain the sources of oils in different tectonic belts. The hydrocarbon charge history was then investigated using an integrated fluid inclusion analysis and basin modelling approach. On the basis of a variety of oil-source correlation geochemical parameters, two distinct oil groups were delineated in this region: Group I including oils in the Yaha and Yingmai-7 tectonic belts, while Group II comprising oils from the Yangtake, Hongqi, and Yudong-2 tectonic belts and the YM-21 well. Oil-source correlations show that Group I oil is sourced from the Upper Triassic Huangshanjie Formation (T3h), while Group II oil is mainly sourced from the lower part of the Middle Jurassic Qiakemake Formation (J2q). Both source rocks are located in the middle and northern parts of the Kuqa Foreland Basin.Basin modelling shows that the T3h source rock began to generate early mature to mature oil at 34 Ma and continued until around 3 Ma. The J2q source rock began to generate early mature to mature oil between after 34 Ma and continued to 12 Ma, mainly in the central part of the J2q source rock. Oil migration modelling indicates that the T3h-sourced oils did not accumulate in the Southern Slope Region until 12–5 Ma, whereas the J2q-sourced oils began to charge into the Southern Slope Region around 5–3 Ma. Coupled with fluid inclusion analysis, the modelling shows that oils originated from the T3h source rock began to charge into the Yaha tectonic belt as early as 6 Ma, and subsequently to the Yingmai-7 tectonic belt which received its initial charge around 4.8 Ma. Oils sourced from the Lower J2q source rock began to charge into the Yangtake tectonic belt around 4 Ma, and then into the Yudong-2 tectonic belt around 3.7 Ma. Oils first charged into the Hongqi and YM-21 areas after 4 Ma. Oils from the T3h and the Lower J2q source rocks continued to charge into the Southern Slope Region until 3 Ma.

Organic petrology and geochemistry of Eocene Suzak bituminous marl, north-central Afghanistan: Depositional environment and source rock potential

Organic geochemistry and petrology of Eocene Suzak bituminous marl outcrop samples from Madr village in north-central Afghanistan were characterized via an integrated analytical approach to evaluate depositional environment and source rock potential. Multiple proxies suggest the organic-rich (TOC ∼6 wt.%) bituminous marls are ‘immature’ for oil generation (e.g., vitrinite Ro < 0.4%, Tmax < 425 °C, PI ≤ 0.05, C29 ααα S/S + R ≤ 0.12, C29 ββS/ββS+ααR≤0.10, others), yet oil seeps are present at outcrop and live oil and abundant solid bitumen were observed via optical microscopy. Whole rock sulfur content is ∼2.3 wt.% whereas sulfur content is ∼5.0–5.6 wt.% in whole rock extracts with high polar components, consistent with extraction from S-rich Type IIs organic matter which could generate hydrocarbons at low thermal maturity. Low Fe-sulfide mineral abundance and comparison of Pr/Ph ratios between saturate and whole extracts suggest limited Fe concentration resulted in sulfurization of organic matter during early diagenesis. From these observations, we infer that a Type IIs kerogen in ‘immature’ bituminous marl at Madr could be generating high sulfur viscous oil which is seeping from outcrop. However, oil-seep samples were not collected for correlation studies. Aluminum-normalized trace element concentrations indicate enrichment of redox sensitive trace elements Mo, U and V and suggest anoxic-euxinic conditions during sediment deposition. The bulk of organic matter observed via optical microscopy is strongly fluorescent amorphous bituminite grading to lamalginite, possibly representing microbial mat facies. Short chain n-alkanes peak at C14–C16 (n-C17/n-C29 > 1) indicating organic input from marine algae and/or bacterial biomass, and sterane/hopane ratios are low (0.12–0.14). Monoaromatic steroids are dominated by C28 clearly indicating a marine setting. High gammacerane index values (∼0.9) are consistent with anoxia stratification and may indicate intermittent saline-hypersaline conditions. Stable C isotope ratios also suggest a marine depositional scenario for the Suzak samples, consistent with the presence of marine foraminifera including abundant planktic globigerinida(?) and rare benthic discocyclina(?) and nummulites(?). Biomarker 2α-methylhopane for photosynthetic cyanobacteria implies shallow photic zone deposition of Madr marls and 3β-methylhopane indicates presence of methanotrophic archaea in the microbial consortium. The data presented herein are consistent with deposition of Suzak bituminous marls in shallow stratified waters of a restricted marine basin associated with the southeastern incipient or proto-Paratethys. Geochemical proxies from Suzak rock extracts (S content, high polar content, C isotopes, normal (αααR) C27–29 steranes, and C29/C30 and C26/C25 hopane ratios) are similar to extant data from Paleogene oils produced to the north in the Afghan-Tajik Basin. This observation may indicate laterally equivalent strata are effective source rocks as suggested by previous workers; however, further work is needed to strengthen oil-source correlations.