Middle-Upper Ordovician Source Rocks Research Articles

Aryl isoprenoids from the Lower Paleozoic in the Tarim Basin, NW China: Insight into deep ancient hydrocarbon exploration

The deep ancient hydrocarbon accumulation in the Tarim Basin was extremely complex. It was characterized by large deep burial, multistage accumulations, multistage adjustments, and multistage secondary alterations, affording limited effectiveness of steroid/terpene biomarkers used widely in oil-source correlation. Aryl isoprenoids (AIs), as a series of diagnostic biomarkers, have attracted increasing attention. For a detailed investigation of AIs from the Lower Paleozoic strata and its internal crude oil in the Tarim Basin, various experimental techniques have been employed. The m/z 133 and 134 mass chromatograms of the AIs confirmed their identification. The anomalously heavy compound-specific δ13C (up to ∼ −16‰) indicated the unequivocal precursor of green sulfur bacteria that was only developed under photic zone euxinia (PZE) conditions. AIs were detected in highly mature source rocks and the crude oils suffered secondary alterations, indicating that AIs might have strong stability and anti-secondary-alteration ability. Based on their widespread distribution in the Lower–Middle Ordovician Heituao Formation (O1-2h Fm) and the Lower Cambrian Yuertus Formation (Є1y Fm) shales, the discovery of AIs in almost all crude oils suggests that the O1-2h Fm and Є1y Fm shales were the primary source rocks for the remarkably abundant Lower Paleozoic deep petroleum resources. This reverses the previously held belief that the Middle-Upper Ordovician source rocks were the primary source rocks. In addition, AIs might induce the formation of organic-rich source rocks (the TOC was up to 29.8%) by promoting high-quality preservation conditions (containing H2S). Furthermore, unlike the H2S poisoning mechanism for the end-Permian mass extinction explained by AIs, regionally distributed AIs triggered by H2S from non-volcanic eruptions could explain the biological radiations (such as the early Cambrian radiation). Therefore AIs might provide important insights into the research on deep ancient petroleum exploration and its contemporaneous biological events.

Quantitatively unmixing method for complex mixed oil based on its fractions carbon isotopes: A case from the Tarim Basin, NW China

Deep mixed oils with secondary alterations have been widely discovered in the Tarim Basin, but current methods based on biomarkers and isotopes to de-convolute mixed oil cannot calculate the exact mixing proportion of different end-member oils, which has seriously hindered further exploration of deep hydrocarbons in the study area. To solve this problem, we constructed a novel method based on the carbon isotope ( δ 13 C) of the group components to de-convolute mixed liquid hydrocarbons under the material balance principle. The results showed that the mixed oil in the Tazhong Uplift was dominantly contributed at an average proportion of 68% by an oil end-member with heavier δ 13 C that was believed to be generated from the Cambrian-Lower Ordovician source rocks, whereas the mixed oil in the Tabei Uplift was predominantly contributed at an average proportion of 61% by an oil end-member with lighter δ 13 C that was believed to be generated from the Middle-Upper Ordovician source rocks. This indicates that, on the basis of the detailed description of the distribution of effective source rocks, the proposed method will be helpful in realizing differential exploration and further improving the efficiency of deep liquid hydrocarbon exploration in the Tarim Basin. In addition, compared to traditional δ 13 C methods for whole oil and individual n-alkanes in de-convoluted mixed oil, the proposed method has a wider range of applications, including for mixed oils with variations in color and density, indicating potential for promoting the exploration of deep complex mixed oils in the Tarim Basin and even around the world.

Geochemical characteristics of Middle-Upper Ordovician source rocks in the Kalpin outcrop profiles and marine oil-source correlation, Tarim Basin, NW China

The Middle-Upper Ordovician source rocks developed in six outcrop profiles in the Kalpin area, Tarim Basin, NW China were analyzed using an organic geochemical screening method. Most TOC values of source rocks of Salgan Formation of Middle-Upper Ordovician developed in the Dawangou, Kamatikan, and Tonggusibulong outcrop profiles are greater than 1.0%, whereas the TOC value of the source rocks of Yingan Formation of Upper Ordovician only developed in the Dawangou outcrop ranged from 0.14% to 1.29%, with an average value lower than that of the Salgan Formation source rocks. Combined with the analysis results of source rocks of Yuertusi Formation of Lower Cambrian developed in the Xiaoerbulake, Sugaite and West Yuti outcrop profiles, the source rocks of Yuertusi, Salgan and Yingan Formations showed similar molecular geochemical characteristics, with low Pr/Ph value, C23 greater than C21 tricyclic terpane, high gamacerane and C28 sterane content. The similarity in molecular compounds of Cambrian to Ordovician source rocks in the Kalpin area may be a result of the high maturity. In the relative distribution of C27–C29 regular steranes, the marine oils with C28 sterane lower than 25% showed great difference with that of the source rocks of Lower Cambrian Yuertusi Formation. In the distribution of carbon isotopic curves, the source rocks of Lower Cambrian Yuertusi Formation have lighter carbon isotopes, compared with that of the Middle-Upper source rocks, especially in kerogen carbon isotopes, Lower Cambrian Yuertusi Formation lighter 5‰ than that of Middle-Upper Ordovician source rocks. Overall, the carbon isotopes fractionation of saturate, bitumen, aromatic fraction, resin, asphaltene, and kerogen is small in source rocks from Middle-Upper Ordovician Salgan and Yingan Formations in the Kalpin area. It is suggested that the carbon isotope of kerogen of source rocks can be used as a parameter for oil-source correlation excluding the TSR of the oil reservoirs.

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.

Quantitative prediction model of present-day low-TOC carbonate source rocks: Example from the Middle–upper Ordovician in the Tarim Basin

Plenty of marine crude oil generated by the Middle–Upper Ordovician source rocks has been discovered in the Tabei Uplift, Tarim Basin. Previous studies on the extensively distributed low organic matter source rock total organic carbon ≤ 0.5%) imply that this contributes to oil accumulation. Thus, the identification of present-day low-total organic carbon source rocks that experience hydrocarbon expulsion and evaluation of their contribution is of considerable significance to analyze marine oil accumulation and to assess the resources in the Tarim Basin. Using the mass balance approach, we identify and verify present-day low-total organic carbon carbonate source rocks and present a quantitative model using well-logging data to predict the present-day low-total organic carbon carbonate source rocks in order to evaluate their contribution in the Tarim Basin. Hydrocarbon expulsion has occurred in the Yijianfang formation, which has present-day low-total organic carbon, between 6452 and 6487 m in the Yangwu 2 well. In the horizons depicting carbonates with hydrocarbon expulsion, the porosity is relatively high and the daily oil production is 0.19 m3 according to the perforation tests. The extracts have similar biomarker signatures to that of the crude oils in the Tabei Uplift. In this study, a quick and cost-effective quantitative model is developed using double lateral resistivity and uranium/thorium well-logging data. By applying the prediction model, the contribution of present-day low-total organic carbon carbonate source rocks in the Middle–Upper Ordovician formation of the Tarim Basin is primarily evaluated to be 363.38 × 109 bbl oil equivalent.

Origin, charging, and mixing of crude oils in the Tahe oilfield, Tarim Basin, China

Forty-eight crude oil samples collected from different reservoirs in the Tahe oilfield of the Tarim Basin were investigated. Based on geochemical characteristics, it is concluded that the oil samples originated from multiple marine source rocks deposited in various sedimentary environments and subsequently altered by different levels of thermal maturation. These mixtures were de-convoluted to three endmember oils (EM1, EM2 and EM3) by alternating least squares regression using 38 concentration parameters. EM1 is the minimum contributor with an average of 13%, while EM2 and EM3 are the main contributors to the mixtures with averages of 52% and 35%, respectively. EM1 oil originated from Cambrian–Lower Ordovician source rocks in the early to peak oil window and subsequently experienced two phases of mixing and biodegradation. EM2 and EM3 oils originated from Middle–Upper Ordovician source rocks, but EM2 was generated at lower thermal maturity than EM3. The EM2 oil underwent two phases of mixing and one stage biodegradation, while the EM3 oil mixed with previous existing mixtures in the reservoirs. The final mixtures that might be affected by secondary processes, such as evaporative fractionation, are currently produced from the Tahe oilfield. The general orientation of oil filling was from south to north and east to west based on variations in the relative contributions of EMs, and the total concentrations of dibenzothiophenes and dibenzofurans in the oils. Considering the histories of sedimentary tectonic evolution, hydrocarbon generation and expulsion, and the de-convolution results, a model of three stages of oil charge and two phases of mixing and biodegradation was established for the Tahe oilfield oils.

Biodegradation and possible source of Silurian and Carboniferous reservoir bitumens from the Halahatang sub-depression, Tarim Basin, NW China

Five core samples comprising three Silurian and two Carboniferous bituminous sandstones from the Halahatang sub-depression (Tarim Basin, NW China) were studied to determine the nature and extent of microbial alteration and possible source(s) of the reservoir bitumens. A total of twelve Ordovician crude oil samples from this sub-depression were also examined for comparative purposes. Co-occurrence of a series of 25-norhopanes (NHs) (C28–C34), variable amounts of chromatographically unresolved complex mixture (UCM), and diminished concentrations of n-alkanes below ca. C20 in saturated hydrocarbon fractions of the Silurian and Carboniferous bitumens indicates that they are mixtures of heavily biodegraded oil from a former charge and slightly biodegraded oil from a later charge. The presence of C28–C34 25-NHs suggests a biodegradation level of at least PM 6 for these bitumen samples. Nevertheless, minor differences in terpane and sterane distributions between the Silurian and Carboniferous bitumen samples were observed which can be attributed to small variations in biodegradation levels. Values for the 25-NH ratio (Peters et al., 1996), gammacerane/(gammacerane + C30 hopane), C28 25-NH/C29 hopane and C29 25-NH/C30 hopane ratios indicate slightly higher levels of microbial alteration for the Silurian bitumens compared to the Carboniferous bitumens, although caution must be exercised when comparing the biodegradation intensities using molecular parameters. The Ordovician crude oil samples appear to be more severely biodegraded than the Silurian and Carboniferous bitumens, as evidenced by higher concentrations of tricyclic terpanes relative to hopanes, and pregnanes and diasteranes relative to the regular steranes, although thermal maturity effects cannot be ruled out. Geochemical correlation studies were successfully applied based on carbon isotopes and biomarkers including tricyclic terpanes and triaromatic steroids which are highly resistant to severe biodegradation (PM 6). Bulk isotopic compositions, distribution patterns and certain ratios of these biomarkers indicate that the Ordovician crude oils and the Silurian and Carboniferous bitumens originated from a single source. They were probably derived from Middle–Upper Ordovician source rocks.

Evaluation method and application of the relative contribution of marine hydrocarbon source rocks in the Tarim basin: A case study from the Tazhong area

In total, 2.37 million tons of marine crude oil originating from mixed source rocks has been discovered in the Tarim basin. Geological and geochemical analyses have confirmed that these mixed hydrocarbons are mainly from two sets of source rocks, including the Cambrian – Lower Ordovician and Middle-Upper Ordovician hydrocarbon source rocks. In this study, we determined the set of source rocks primarily responsible for the mixed hydrocarbons and the next location to be explored. Differences in n-alkane carbon isotopes in end-member oils from Cambrian–Lower Ordovician and Middle-Upper Ordovician source rocks were examined. A material balance model and simulation methods were used to evaluate the relative amounts contributed by each source. The results from known reserves in the Tazhong area show that the mixing ratio or contribution is up to 65% from Cambrian–Lower Ordovician source rocks and is generally higher than that from Middle-Upper Ordovician source rocks. The discovery of deep hydrocarbons has caused the total oil contribution from the Cambrian–Lower Ordovician to increase. The mixing ratio of Cambrian–Lower Ordovician oil varies depending on the well, formation, and block. It increases from west to east horizontally and from top to bottom vertically. Hydrocarbons from Cambrian–Lower Ordovician source rocks migrate upward along faults, and the mixing ratio decreases as the distance from the oil source fault increases. Favorable areas for Cambrian–Lower Ordovician hydrocarbon exploration are deep layers and areas near the fault zone that are connected to deep layers. The material balance model for carbon isotopes and evaluation methods for relative contributions considered differences in relative concentration and carbon isotope structure of n-alkanes. Herein, new methods for the identification and evaluation of hydrocarbons in the petroleum system of this superimposed basin are presented.

De-convoluting crude oil mixtures from Palaeozoic reservoirs in the Tabei Uplift, Tarim Basin, China

Geochemical characteristics of 61 crude oil samples collected from Palaeozoic reservoirs in the Tarim Basin (60 from the Tabei Uplift and one from the Tazhong Uplift) were analyzed. The samples proved to be mixed oils of different maturity from diverse source rocks. Concentrations of 40 biomarkers and carbon isotopic compositions for the whole oils were analyzed by alternating least squares (ALS) regression to de-convolute the mixtures. Three endmember (EM) oils were identified. EM1 is the minimum contributor to the mixed oils, accounting for less than 10% of most oils. EM1 originated from Cambrian–Lower Ordovician source rocks in the early to peak oil window stage and experienced two phases of mixing and biodegradation. EM2 is the secondary contributor with proportions ranging from 10% to 40% in most oil samples. EM2 originated from Middle–Upper Ordovician source rocks at the early oil generation stage and underwent two phases of mixing and one stage biodegradation in the reservoirs. EM3 is the major contributor to most samples with proportions ranging from 13% to 95%. EM3 was generated from Middle–Upper Ordovician source rocks at the late oil generation stage and mixed with earlier emplaced mixtures in the reservoirs. The final mixtures that were not biodegraded are currently exploited from Palaeozoic reservoirs in the Tabei Uplift. Biomarkers in the crude oils reveal mixed characteristics, including evidence for two phases of oil charge and severe biodegradation.

Controlling factors and genesis of hydrocarbons with complex phase state in the Upper Ordovician of the Tazhong Area, Tarim Basin, China

Seven hydrocarbon reservoirs have been discovered to date in the Upper Ordovician of the Tazhong Area, a region in which hydrocarbon phase distribution is complex. In the present study, the genesis and controlling factors of the hydrocarbons with complex phase in the Tazhong Area were investigated on the basis of the geological and geochemical conditions required for the formation and distribution of hydrocarbon reservoirs, integrated with the source rock geochemistry, natural gas and oil properties, and oil and gas reservoir fluid tests PVT (i.e., pressure, volume, and temperature tests). The results indicate that hydrocarbon reservoir types in the Upper Ordovician of the Tazhong Area transition from unsaturated to saturated condensate-gas reservoirs from west to east and from condensate-gas reservoirs to unsaturated-oil reservoirs from north to south. The crude oil in the region originated primarily from the mixing of Lower–Middle Cambrian and Middle–Upper Ordovician source rocks, while the natural gas was sourced primarily from the cracking gas of Lower–Middle Cambrian crude oil. This hydrocarbon-phase distribution was controlled primarily by temperature and pressure and has been affected by multiple periods of hydrocarbon accumulation and alteration. The high-quality Lower–Middle Cambrian reservoir–cap assemblage may be an important target for future exploration of natural gas in the Tazhong Area.

Predicting potential exploration targets based on key factors controlling hydrocarbon accumulation—a case study from the Lower Ordovician Yingshan Formation in the Tazhong area, Tarim Basin, NW China

The Tazhong area, at the centre of the Tarim Basin, northwestern China, contains abundant hydrocarbon resources and features complex geological setting, principally in the Lower Ordovician carbonate reservoirs. Despite years of exploration and development, the hydrocarbon accumulation mechanisms and the key factors controlling hydrocarbon accumulation are still unclear. This lack of knowledge is the critical factor restricting hydrocarbon exploration in the Lower Ordovician Yingshan Formation. An analysis of the geological setting and reservoir distribution characteristics, the accumulation mechanisms and the key factors are investigated to predict the target exploration area. Our results show that the hydrocarbons, which experienced four stages of accumulation, originated from mixed sources including Cambrian–Lower Ordovician and Middle–Upper Ordovician source rocks within the Tazhong area and beyond. Hydrocarbons, by point charging, migrated into weathering crust karst reservoirs along 10 intersections of northeast and northwest fault sets, and then laterally migrated, principally in the NW–SE direction. The Yingshan Formation carbonate reservoirs are typically lithologically defined and primarily controlled by differential capillary forces. The accumulation and distribution of hydrocarbons in the Yingshan Formation were controlled by excellent reservoirs and hydrocarbon charge energy. The physical properties of excellent reservoirs control the petroliferous features and the hydrocarbon accumulation threshold: these reservoirs have a threshold with the minimum porosity and permeability, approximately 1.8% and 0.1 mD, and have a threshold with the maximum capillary forces, approximately 2.5 MPa. Hydrocarbon charge energy controls the hydrocarbon enrichment range: hydrocarbons enriched in areas near injection points and the hydrocarbon charge distance threshold of 20 km. Excellent reservoirs and hydrocarbon charge energy coupled index (RSI) controls hydrocarbon accumulation and distribution. Accumulation does not occur when the value of RSI is <0.5 but is favoured when values are higher. The coupled index is used to predict that lithological reservoirs in the Yingshan Formation are mainly distributed in the northeastern area of the ZG17–TZ72 well field, the area between the ZG17 well field and ZG22 well field, and the southwestern area of the ZG44–ZG53 well field.

Origin and quantitative source assessment of deep oils in the Tazhong Uplift, Tarim Basin

A large amount of deep oil has been discovered in the Tazhong Uplift, Tarim Basin whereas the oil source is still controversial. An integrated geochemical approach was utilized to unravel the characteristics, origin and alteration of the deep oils. This study showed that the Lower Cambrian oil from well ZS1C (▪1x) was featured by small or trace amounts of biomarkers, unusually high concentration of dibenzothiophenes (DBTs), high δ34S of DBTs and high δ13C value of n-alkanes. These suggest a close genetic relationship with the Cambrian source rocks and TSR alteration. On the contrary, the Middle Cambrian oils from well ZS1 (▪2a) were characterized by low δ13C of n-alkanes and relatively high δ34S of individual sulfur compounds and a general “V” shape of steranes, indicating a good genetic affinity with the Middle–Upper Ordovician source rocks. The middle Cambrian salt rock separating the oils was suggested to be one of the factors responsible for the differentiation. It was suggested that most of the deep oils in the Tazhong Uplift were mixed source based on biomarkers and carbon isotope, which contain TSR altered oil in varied degree. The percentage of the oils contributed by the Cambrian–Lower Ordovician was in the range of 19–100% (average 57%) controlled by several geological and geochemical events. Significant variations in the δ34S values for individual compounds in the oils were observed suggesting a combination of different extent of TSR and thermal maturation alterations. The unusually high DBTs concentrations in the Tazhong-4 oilfield suggested as a result of mixing with the ZS1C oil (▪1x) and Lower Ordovician oils based on δ34S values of DBT. This study will enhance our understanding of both deep and shallow oil sources in the Tazhong Uplift and clarify the formation mechanisms of the unusually high DBTs oils in the region.

Geological features and hydrocarbon accumulation in the Xinken oil field, Tarim Basin

Recently, a large-scale Ordovician oil and gas pool has been discovered in Xinken, north of the Tarim Basin, and it has strongly heterogeneous reservoirs and complicated fluid distribution. Through analyzing oil, gas and water samples collected from this area, in combination of field production and testing data, this study reveals that the Xinken oil pool contains dominantly normal oil characterized by low viscosity, low sulphur, and high wax. It has a low content of natural gas, which presents typical characteristics of wet gas and is oil-associated gas. Oil-gas correlation shows that the oil was from the Middle-Upper Ordovician source rocks and the charge and accumulation of oil and gas took place in the Late Hercynian Period. Controlled by paleogeomorphology, sedimentary facies, ancient karstification, faults, and other factors in the Caledonian Period, the Ordovician carbonate reservoirs are dominated by dissolved pores, cavities and fractures. The reservoir body of fractures and cavities is distributed in the shape of strip and laminate along faults and excellent reservoirs are mostly in the range of 70–100 m below the top of the Yijianfang Formation. As a whole, the Xinken oil pool is a fracture-cavity pool controlled by interbedded karst reservoirs and is a complex composed of stacked karst fractures and cavities of various sizes. It contains oil in large areas horizontally, which is quasi-laminated in distribution, and the accumulation of oil and gas is controlled by the distribution and development degree of the Ordovician carbonate reservoirs. The study shows that this area has abundant resources and a great exploration potential for oil and gas.

Formation mechanisms of secondary hydrocarbon pools in the Triassic reservoirs in the northern Tarim Basin

The northern Tarim Basin (Tabei) is a rich composite hydrocarbon accumulation region with multi-layers of oil and gas reservoirs in the Ordovician, Carboniferous and Triassic strata. In the Triassic, the Tabei region was dominated by non-marine sedimentation that developed deltaic sandstone reservoirs with favourable petrophysical properties for hydrocarbon accumulations. Hydrocarbons in the Triassic hydrocarbon pools are dominated by oil and condensate gas. Analysis of the hydrocarbons, in combination with well testing and drilling data, reveals that oils in the Triassic hydrocarbon pools are commonly biodegraded and originated mainly from the middle-upper Ordovician source rocks. The predominant dry gases in the reservoirs are cracked from oils derived from the Cambrian source rocks. The origin of hydrocarbons in the Triassic pools is similar to those in the underlying reservoirs. Fluid inclusions and K–Ar dating confirm that the hydrocarbons were accumulated during the Himalayan orogenic movement. Because the middle–upper Ordovician source rocks already experienced peak hydrocarbon generation in the late Hercynian orogeny (late Permian), the Triassic hydrocarbon pools are from secondary adjustment of earlier oil and gas pools from the underlying Ordovician and Carboniferous reservoirs. Due to the rapid subsidence of the Kuqa foreland basin to the north of the Tabei region since the beginning of the Himalayan orogenic movement, the Triassic reservoir strata was changed from south-dipping to north-dipping, resulting in the formation of plunging anticlines and hydrocarbon migration toward the south. At the same time, fault reactivation occurred in the area, causing the hydrocarbons from the deeper reservoirs to migrate into the Triassic structural traps through faults and unconformities, and thus formed the widespread secondary hydrocarbon pools. The structure inversion during the Triassic and the formation of nose structures since the Himalayan orogeny (250 ∼ 290 Ma, Permian) controlled the secondary accumulation in the Triassic reservoirs. The reformation process of the hydrocarbon pools continued until the late Himalayan orogeny when the gas was charged and developed condensate pools in the eastern area.

Key factors controlling hydrocarbon accumulations in Ordovician carbonate reservoirs in the Tazhong area, Tarim basin, western China

The Tazhong area, at the center of the Tarim basin, western China, contains abundant hydrocarbon resources, principally in Ordovician carbonate reservoirs. The geological conditions for hydrocarbon accumulation in the area are quite complicated and are characterized by multiple stages of hydrocarbon generation, accumulation, adjustment and alteration. Despite decades of exploration and production in the region, the mechanisms of hydrocarbon accumulation and their controlling factors are still not well established. The geological setting and the distribution characteristics of the reservoir, have been used to investigate the mechanisms of accumulation, to quantitatively describe the main controlling factors, and to predict potential favorable hydrocarbon accumulation zones in Ordovician carbonate rocks of Tazhong. Our results show that the hydrocarbons in the Ordovician reservoirs came from mixed sources including middle-lower Cambrian and middle-upper Ordovician source rocks within the Majiaer Sag. Four stages of accumulation are recognized and hydrocarbons migrated into the Tazhong area along six intersections of NE and NW fault sets, principally from the northeast to the southwest but then, locally, from the northwest to the southeast. The Ordovician carbonate reservoirs are typically lithologically defined and the dynamic force of hydrocarbon accumulation is primarily reflects differential capillary forces. The accumulation and distribution of hydrocarbons was controlled by the petrophysical properties of the reservoir and by hydrocarbon supply/charge energy. The petrophysical properties of the reservoir controlled the hydrocarbon accumulation threshold with the maximum differential capillary pressure force, on average, approximately 13 MPa. The supply or charge energy of the hydrocarbons controls the accumulation distribution range. The daily production of individual wells decreases with increasing distance from the fault intersections and the maximum hydrocarbon migration distance is about 35 km. Reservoir properties and the hydrocarbon supply/charge Energy coupling Index (REI) appear to control hydrocarbon accumulation and distribution. Accumulation does not occur when the value of REI is ≤ 0.6, but is favored when values are higher.

The occurrence of ultra-deep heavy oils in the Tabei Uplift of the Tarim Basin, NW China

Deeply buried heavy oils from the Tabei Uplift of the Tarim Basin have been investigated for their source origin, charge and accumulation time, biodegradation, mixing and thermal cracking using biomarkers, carbon isotopic compositions of individual alkanes, fluid inclusion homogenization temperatures and authigenic illite K–Ar radiometric ages. Oil-source correlation suggests that these oils mainly originated from Middle–Upper Ordovician source rocks. Burial history, coupled with fluid inclusion temperatures and K–Ar radiometric ages, suggests that these oils were generated and accumulated in the Late Permian. Biodegradation is the main control on the formation of these heavy oils when they were elevated to shallow depths during the late Hercynian orogeny. A pronounced unresolved complex mixture (UCM) in the gas chromatograms together with the presence of both 25-norhopanes and demethylated tricyclic terpanes in the oils are obvious evidence of biodegradation. The mixing of biodegraded oil with non-biodegraded oil components was indicated by the coexistence of n-alkanes with demethylated terpanes. Such mixing is most likely from the same phase of generation, but with accumulation at slightly different burial depths, as evidenced by overall similar oil maturities regardless of biodegradation level and/or amount of n-alkanes. Although these Ordovician carbonate reservoirs are currently buried to over 6000m with reservoir temperatures above 160°C, no significant secondary hydrocarbon generation from source rocks or thermal cracking of reservoired heavy oil occur in the study area. This is because the deep burial occurred only within the last 5Ma of the Neogene, and there has not been enough heating time for additional reactions within the Middle–Upper Ordovician source rocks and reservoired heavy oils.

Identification and distribution of chrysene, methylchrysenes and their isomers in crude oils and rock extracts

Chrysene, its methylated homologues and their structural isomers are important polyaromatic compounds in crudes oils, coals and sediment extracts. Chrysene, benzo[a]anthracene, methylchrysenes and methylbenzo[a]anthracenes were unequivocally identified in mass chromatograms by comparison with authentic standards and by retention indices reported in the literature. The response factors relating those of chrysene and methylchrysenes to internal standards [perdeuterated chrysene (chrysene-d12) and pyrene (pyrene-d10)] were obtained by GC–MS analyses of mixture solutions with different concentration ratios. The oil families of Ordovician reservoirs in the cratonic region of the Tarim Basin (NW China) are distinguished by the distribution patterns of chrysene, methylchrysenes and their isomers. The majority of the oil accumulations and sediment extracts from the Middle–Upper Ordovician source rocks are characterized by low concentrations of benzo[a]anthracene and methylbenzo[a]anthracenes relative to chrysene and methylchrysenes, respectively. In contrast, some oils with relatively high abundances of benzo[a]anthracene and methylbenzo[a]anthracenes were derived from Cambrian and Lower Ordovician source rocks. The effect of maturity on the distribution patterns of methylchrysenes in Tertiary lacustrine shales from the Liaohe Basin (East China) was investigated. The 2-/1-methylchrysene ratio keeps a nearly constant value with increasing maturity at the low maturity stages and then it abruptly increases, corresponding approximately to the onset of intense C15+ hydrocarbon generation. This indicates that chrysene and its methylated homologues are useful molecular indicators in petroleum geochemistry.

Geochemical quantification of mixed marine oils from Tazhong area of Tarim Basin, NW China

Located in the center of the Tarim Basin, NW China, Tazhong area was found to be enriched in oil and gas resources, and the resources are mainly originated from two sets of marine source rocks, namely, the Cambrian-Lower Ordovician (ϵ-O1) source rocks and the Middle-Upper Ordovician (O2+3) source rocks. Due to complex post-depositional alterations such as multiple episodes of hydrocarbon generation, migration and accumulation, most oil reservoirs in this area occur as mixed oils.Results of geochemical studies of crude oils, combined with bulk stable carbon isotope data of 108 oil samples, indicate that most marine oils from Tazhong area are mixtures sourced from both the ϵ-O1 and O2+3 strata. Based on bulk stable carbon isotope data of the oils, quantification studies were made to evaluate the relative contributions of different source rocks to the mixed oils, and the results show that the Middle-Upper Ordovician source rocks are the main contributor for the oils in the Tazhong area, despite fewer exceptions that some oil reservoirs were mainly originated from the Cambrian-Lower Ordovician source rocks. However, for the oil reservoirs occurring in different subunits in the Tazhong area, the relative contributions from different source rocks do not show regular distribution patterns, implying that Tazhong area was subject to multiple episodes of hydrocarbon generation, migration and accumulation in geological history.

Multiple-sourced features of marine oils in the Tarim Basin, NW China – Geochemical evidence from occluded hydrocarbons inside asphaltenes

The Tarim Basin, NW China, is a large composite basin with multiple sets of petroleum source rocks. The basin has undergone numerous episodes of hydrocarbon generation, migration and accumulation, making it difficult to assess the source rocks and oil–source correlation for the widespread marine oils in this area.Protected by the molecular structure of asphaltenes, occluded hydrocarbons can provide information about the early source rocks. In this work, the occluded hydrocarbons released from the asphaltenes by a mild chemical degradation method were compared with the crude oil maltenes and the adsorbed compounds from asphaltenes. Analysis of biomarker distribution and the carbon isotope composition of individual n-alkanes suggests that the widespread marine oils in the Tazhong Uplift, Tabei Lunnan Uplift and Halahatang Depression were contributed by Cambrian–Lower Ordovician source rocks at an early stage, and later mixed with hydrocarbons derived from Middle-Upper Ordovician source rocks. The marine oils in the Tarim Basin demonstrate extensive characteristics of having been derived from multiple source rocks.

The significance of 24-norcholestanes, triaromatic steroids and dinosteroids in oils and Cambrian–Ordovician source rocks from the cratonic region of the Tarim Basin, NW China

Abstract Two oil families in Ordovician reservoirs from the cratonic region of the Tarim Basin are distinguished by the distribution of regular steranes, triaromatic steroids, norcholestanes and dinosteroids. Oils with relatively lower contents of C 28 regular steranes, C 26 20S, C 26 20R + C 27 20S and C 27 20R regular triaromatic steroids, dinosteranes, 24-norcholestanes and triaromatic dinosteroids originated from Middle–Upper Ordovician source rocks. In contrast, oils with abnormally high abundances of the above compounds are derived from Cambrian and Lower Ordovician source rocks. Only a few oils have previously been reported to be of Cambrian and Lower Ordovician origin, especially in the east region of the Tarim Basin. This study further reports the discovery of oil accumulations of Cambrian and Lower Ordovician origin in the Tabei and Tazhong Uplifts, which indicates a potential for further discoveries involving Cambrian and Lower Ordovician sourced oils in the Tarim Basin. Dinosteroids in petroleum and ancient sediments are generally thought to be biomarkers for dinoflagellates and 24-norcholestanes for dinoflagellates and diatoms. Therefore, the abnormally high abundance of these compounds in extracts from the organic-rich sediments in the Cambrian and Lower Ordovician and related oils in the cratonic region of the Tarim Basin suggests that phytoplankton algae related to dinoflagellates have appeared and might have flourished in the Tarim Basin during the Cambrian Period. Steroids with less common structural configurations are underutilized and can expand understanding of the early development history of organisms, as well as define petroleum systems.