Ordovician Source Rocks Research Articles

Geochemistry and possible origin of the hydrocarbons from Wells Zhongshen1 and Zhongshen1C, Tazhong Uplift

In 2013, a great breakthrough of deep petroleum exploration was achieved in the Cambrian pre-salt intervals of Wells Zhongshen1 (ZS1) and Zhongshen1C (ZS1C), Tazhong Uplift. However, the hydrocarbon discovery in the Cambrian pre-salt intervals has triggered extensive controversy regarding the source of marine oils in the Tarim Basin. The geochemistry and origin of the Cambrian pre-salt hydrocarbons in Wells ZS1 and ZS1C were investigated using GC, GC-MS and stable carbon isotope technique. These hydrocarbons can be easily distinguished into two genetic families based on their geochemical and carbon isotopic compositions. The oil and natural gases from the Awatage Formation of Well ZS1 are derived from Middle- Upper Ordovician source rocks. In contrast, the condensate and gases from the Xiaoerbulake Formation of Wells ZS1 and ZS1C probably originate from Cambrian source rocks. The recent discovery of these hydrocarbons with two different sources in Wells ZS1 and ZS1C suggests that both Middle-Upper Ordovician-sourced hydrocarbons and Cambrian-sourced petroleums are accumulated in the Tazhong Uplift, presenting a great exploration potential.

The Distribution of Triaromatic Steroids and Oil Group Classification of Ordovician Petroleum Systems in the Cratonic Region of the Tarim Basin, NW China

A practical method to estimate the abundance of each C26-C28 triaromatic steroid isomer was proposed and a triangular diagram can therefore be drawn to distinguish oil populations in the cratonic region of the Tarim Basin, NW China. The results indicate that oils discovered in this region can be divided into two petroleum systems. Oils derived from the Cambrian and Lower Ordovician source rocks show relatively high abundance of C27 triaromatic steroids with the relative abundance of C27 TAS being more than 25% of all TAS isomers. In contrast, the values are below 25% in oils and source rocks from the Middle-Upper Ordovician. The petroleum system definition is in agreement with previous studies using regular steranes, tricyclic terpanes, norcholestanes, and other molecular markers to distinguish oil groups. In addition, high thermal stability and greater resistance to biodegradation make triaromatic steroids more effective in distinguishing oil groups in the tectonic region of the Tarim Basin.

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.

The Paleozoic Hudson Bay Basin in northern Canada: New insights into hydrocarbon potential of a frontier intracratonic basin

The Hudson Bay Basin is the largest intracratonic basin in North America, although it is the only one without any proven hydrocarbon reserves. The stratigraphic succession that fills the basin consists mainly of Paleozoic strata, with a maximum preserved thickness of about 2500 m (8202 ft). The Paleozoic succession includes Ordovician to Devonian shallow marine carbonates, reefs, and shales with locally thick Devonian evaporites. The Paleozoic strata are locally unconformably overlain by a thin Mesozoic and Cenozoic cover of nonmarine and marine strata. From 1964 to 1985, over 46,000 line-km (28,600 mi) of seismic reflection data were acquired, and four onshore and five offshore exploration wells were drilled. The data acquired at that time led to pessimistic conclusions on source rocks and the thermal rank of the basin and resulted in the stoppage of exploration activities. However, hydrocarbon shows or indicators were identified in well log data and seismic reflection profiles. The likelihood of an active petroleum system has also been recently supported by recognition of pockmarks on the seafloor and possible marine oil slicks identified on satellite images. New studies of geological, geophysical, and biostratigraphic data reveal that the Hudson Bay Basin had an irregular subsidence and uplift history. Syntectonic deposition occurred during the Late Ordovician(?) to Early Devonian and sag-basin deposition during the Middle to Late Devonian. The basin contains four unconformity-bounded sequences, with significant depocenter migration over time. Analyses of petroleum-system data indicate the Hudson Bay Basin has higher petroleum potential than previously considered. Porous platform limestones, reefs, hydrothermal dolomites, and siliciclastics form potential hydrocarbon reservoirs. Upper Ordovician organic-rich shales with type II-S organic matter are recognized at several locations in the basin. Newly acquired organic matter reflectance and Rock-Eval data indicate Ordovician–Silurian strata locally reached the oil window. Basin modeling demonstrates significant potential for oil generation and expulsion from Ordovician source rocks. Five petroleum play types are identified in the Hudson Bay Basin, including an untested fault-sag or hydrothermal dolomite play. The synthesis of the petroleum system information indicates that the Hudson Bay Basin is, at least locally, prospective for oil accumulations.

Application of an odd/even predominance of n-alkanes in oil–source rock correlation: taking the lower Paleozoic strata of the Tarim Basin as an example

The composition and distribution of n-alkanes carbon numbers reflect the source of kerogenic organic matter, sedimentary environment, and maturity of the rocks. The comparison results of the n-alkanes GC (gas chromatography) chromatograms in the Tazhong Low Uplift show that the n-alkanes of the source rocks in Upper Ordovician display an odd carbon number predominance. At the same time, Cambrian–Lower Ordovician exhibit an even carbon number predominance. The correlation between oil and source rock illustrates that crude oils in the fields of well TZ10-12 and well TZ24 stem from the Upper Ordovician source rocks. The origins of the crude oils in the fields of well TZ161-162 and well TZ45 are Cambrian–Lower Ordovician. The strata corresponding to the crude oils with odd/even carbon number predominance match the oil–source rock correlation. Thus, the characteristics of odd/even carbon number predominance in n-alkane compounds are effective for oil–source rock correlation in the Tazhong Low Uplift, Tarim Basin.

Geology and Hydrocarbon Accumulation of the Large Ultra-Deep Rewapu Oilfield in Tarim Basin, China

Over the past five years, oil and gas exploration to marine facies carbonate rock in China took on a fast-growing tendency, and a lot of large-scale oil and gas fields were discovered in succession. Particularly in the north of Tarim Basin, the large-scale Rewapu oil field was recently discovered in the Ordovician carbonate rock layer system with buried depth of 7,000 meters, manifesting that a significant potential of exploration exists in Tarim Basin's deep layer and ultra deep layer of Tarim basin. The results indicate that reservoirs of Rewapu oilfield are low porosity and low permeability layers karst reservoirs, reservoir temperature is around at 160 °C with oil, and the crude oil comes from the upper Ordovician source rock of the Manjaer depression. The hydrocarbon accumulation time is in the Late Permian, and since the Triassic sedimentation, the reservoir is in the continuous process of burying. It belongs to the old oil and gas system. Due to low geothermal gradient and late quick deep burial, oil reservoir has yet to be cracked, so well-preserved old oil reservoir can be discovered at the depth of 7000 m. The Ordovician carbonate reservoir in Rewapu was a fracture-cavity oil reservoir, and the oil and gas distribution and enrichment are controlled not by the local structure, but by the distribution and the development degree of Ordovician carbonate reservoir. The reservoirs of Rewapu block are mainly distributed in the Ordovician Yijianfang formation and at the top Yingshan formation, and the reservoir development degree was controlled by the karstification, the degree of fracture development and the sedimentation facies, concentrating into belts in plane and not controlling by the depth vertically. The overlying strata are limestone of Tumuxiuke formation and marls and limestone of Sangtamu formation in the upper Ordovician. Rewapu oil reservoir features stratified oil and mainly contains normal oil with low viscosity and high wax. Research results show that Ordovician reservoirs in Rewapu block have relatively large depth of burial, but they are still favorable in quality and sit along the path for the oil and gas's northward migration. Therefore, this block has immense resources potential and boasts good exploration and development outlook. In this paper, we study Rewapu block oil reservoir's geological features and hydrocarbon accumulation mechanism, which is of important significance for directing the exploration to oil and gas at the deep layer and ultra deep layer of Tarim Basin.

Application of sulfur and carbon isotopes to oil–source rock correlation: A case study from the Tazhong area, Tarim Basin, China

Up until now, it has been assumed that oil in the Palaeozoic reservoirs of the Tazhong Uplift was derived from Upper Ordovician source rocks. Oils recently produced from the Middle and Lower Cambrian in wells ZS1 and ZS5 provide clues concerning the source rocks of the oils in the Tazhong Uplift, Tarim Basin, China. For this study, molecular composition, bulk and individual n-alkane δ13C and individual alkyl-dibenzothiophene δ34S values were determined for the potential source rocks and for oils from Cambrian and Ordovician reservoirs to determine the sources of the oils and to address whether δ13C and δ34S values can be used effectively for oil–source rock correlation purposes. The ZS1 and ZS5 Cambrian oils, and six other oils from Ordovician reservoirs, were not significantly altered by TSR. The ZS1 oils and most of the other oils, have a “V” shape in the distribution of C27–C29 steranes, bulk and individual n-alkane δ13C values predominantly between −31‰ to −35‰ VPDB, and bulk and individual alkyldibenzothiophene δ34S values between 15‰ to 23‰ VCDT. These characteristics are similar to those for some Cambrian source rocks with kerogen δ13C values between −34.1‰ and −35.3‰ and δ34S values between 10.4‰ and 21.6‰. The oil produced from the Lower Ordovician in well YM2 has similar features to the ZS1 Cambrian oils. These new lines of evidence indicate that most of the oils in the Tazhong Uplift, contrary to previous interpretations, were probably derived from the Cambrian source rocks, and not from the Upper Ordovician. Conversely, the δ13C and δ34S values of ZS1C Cambrian oils have been shown to shift to more positive values due to thermochemical sulfate reduction (TSR). Thus, δ13C and δ34S values can be used as effective tools to demonstrate oil–source rock correlation, but only because there has been little or no TSR in this part of the section.

BIOMARKER CHARACTERISTICS OF POTENTIAL SOURCE ROCKS IN THE JABAL NAFUSAH AREA, NW LIBYA: PETROLEUM SYSTEMS SIGNIFICANCE

The Jifarah Arch of NW Libya is a structurally prominent feature at the eastern end of the regional Talemzane Arch, separating the Ghadamis hydrocarbon province to the south from the offshore Pelagian province to the north. The Arch has experienced a complex structural history with repeated episodes of uplift, exhumation and burial. This paper provides a provisional assessment of its hydrocarbon habitat based on detailed geochemical analyses of potential Triassic, Silurian and Ordovician source rocks encountered by wells drilled in the area.Twenty‐seven core and cuttings samples of marine shales were collected from eight widely‐ dispersed wells and analyzed using standard Rock‐Eval pyrolysis techniques. Kerogen types II‐III were identified in the majority of Triassic samples analysed, indicating a low hydrocarbon generation potential, but oil‐prone Type II kerogen was found in the basal Silurian Tanezzuft Formation and Ordovician Memouniat Formation. The presence of steranes and acyclic isoprenoids suggested variable inputs of algal, bacterial and terrestrial organic matter, while biomarkers including C30‐gammacerane and β–carotene and selected biomarker ratios (Pr/Ph ratio and homohopane index) were used to assess their depositional environment. Results indicate that extended zones with periodic (if not continuous) oxygen‐deficient conditions existed throughout the basin during Late Ordovician and Early Silurian time, favouring the preservation of organic matter.The thermal maturity of the samples was assessed by Rock‐Eval pyrolysis, zooclast reflectance, molecular ratios including C32‐22S/(22S+22R)‐homohopanes, Ts/(Ts+Tm), C29‐steranes and parameters based on the relative abundance of methylphenanthrene, methyldibenzothiophene and methylnaphthalene isomers. The results indicate significant variability in thermal maturity, with Ordovician and Silurian source rocks ranging from 0.6% to 0.7% VRo equivalent increasing to 1.0% locally. These values represent palaeo‐maturities achieved at different times in the past and are considered too low to have generated significant volumes of hydrocarbons directly. However the downdip equivalents of these source rocks in the adjacent Ghadamis Basin contributed to prolific petroleum systems. The absence of large petroleum accumulations on the Jifarah Arch contrasts with the western part of the geologically similar Talemzane Arch, which harbours several giant and supergiant oil and gas fields. This difference is attributed both to the complex structural history of the Jifarah Arch, which permitted post‐charge leakage of palaeo‐accumulations, and stratigraphic migration barriers which restricted migration between Tanezzuft source rocks and Ordovician and Triassic reservoirs.

Tectonic fracture and its significance in hydrocarbon migration and accumulation: a case study on middle and lower Ordovician in Tabei Uplift of Tarim Basin, NW China

Middle and lower Ordovician carbonate rock in the Tabei Uplift of the Tarim Basin forms important fractured reservoir beds. Core and log data indicate that tectonic fractures, as the main fractures in the Tabei Uplift, could be mainly classified into two types: oblique fractures and approximately vertical fractures. The fractures are mainly NNW‐trending and NNE‐trending, coincident with the large faults nearby. Fracture abundance was also controlled by lithology, and faults nearby played a significant role. Cores, thin sections and tests show that these carbonate rocks have as much as 2.5% fracture porosity and as much as 150 md fracture permeability. Based on the intersection of fractures in cores, together with fluid inclusion temperature data, and the timing of faulting from seismic profiles, tectonic fractures were considered to be mainly formed in three periods: the late Silurian when the first‐stage oblique fractures were formed, the late Permian when approximately vertical fractures were formed, and the late Tertiary when the second‐stage oblique fractures were formed. Lower Cambrian source rocks started to enter the stage of generous hydrocarbon generation and expulsion in the Silurian. Ordovician source rocks started to enter the stage of generous hydrocarbon generation and expulsion in the Permian and enter the over‐mature stage in the late Tertiary when light oil was generated. Timing of tectonic fractures formation and burial history analysis suggest that fractures formation might coincide with oil accumulation when fractures provided the pathway and storage space for the low permeability and low porosity reservoir beds caused by previous compaction and cementation. Considering the presence of a large amount of fracture‐developed dolomite in the deeper Ordovician Penglaiba Formation, the undrilled Penglaiba Formation should be paid more attention. Copyright © 2015 John Wiley &amp; Sons, Ltd.

Distribution of C26 norcholestanes in Ordovician crude oils from Tahe Oilfield and its geological significance

Abstract A series of C26 norcholestanes was detected in the Ordovician crude oils from the Tahe Oilfield, the Tarim Basin, northwest China. The abundance of 24-norcholestanes in most of the Ordovician crude oils was lower than that of 27-norcholestanes. The oils from well T904 in the eastern Tahe Oilfield and well TD2 in the eastern Tarim Basin, however, were characterized by relatively higher 24-norcholestane abundance. The distribution of C26 norcholestane of the Upper Ordovician marls from the wells LN46 and BD2 resembled that of the most Ordovician crude oils from the Tahe Oilfield. The distribution of C26 norcholestanes in typical Cambrian black shales and gray limestones from the wells TD2, He4 and outcrops from Keping profile resembled that of the crude oils from the wells T904 and TD2. Criteria are proposed relative to C26 norcholestanes that could be used to classify oil families within the Ordovician reservoirs. Oils with NCR (defined as 24/ (24+27)-norcholestanes) &gt;0.50 and NDR (defined as 24/ (24+27)-nordia-cholestanes) &gt;0.35 were thought to be derived from the Cambrian source rocks, and oils with NCR&lt;0.40 and NDR&lt;0.35 were thought to be derived from the Upper Ordovician source rocks. Therefore, C26 norcholestanes were effective molecular markers to classify oil genetic families in the Tahe Oilfield. They could also provide molecular evidence for the origin and evolution of diatoms and dinoflagellates and the plate drift of the Tarim Basin.

Comprehensive diagnostic review of the 13C-enriched crude oils exemplified by TD2Є and TZ62S in Tarim Basin, NW China

The crude oils typically from the Cambrian-Lower Ordovician source rocks of Tarim Basin, NW China, such as TD2Є and TZ62S, are 13C-enriched with the stable carbon isotopic ratios (VPDB) approaching −28 ‰. In this paper, the main research viewpoints on this issue are summarized, and combined with results from organic and inorganic carbon isotope stratum curves of the outcrop at the Ya’erdang Mountain in Tarim Basin. In addition, more alternative interpretations are discussed. On one hand, the inverse fractionation features of stable carbon and hydrogen isotopes of these crude oils may imply their protogenous nature. On the other hand, the anisotropy of source rocks and contribution from older stratum source rocks need verifying as well. For the sake of the final resolution of this issue, some further study topics are recommended.

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.

The distribution characteristic and its significance of compound specific isotopic composition of aromatic hydrocarbon from marine source rock and oil in the Tarim Basin, western China

Aromatic hydrocarbons are generally main distillation of crude oil and organic extract of source rocks. Bicyclic and tricyclic aromatic hydrocarbons can be purified by two-step method of chromatography on alumina. Carbon isotopic composition of individual aromatic hydrocarbons is affected not only by thermal maturity, but also by organic matter input, depositional environment, and hydrocarbon generation process based on the GC-IRMS analysis of Upper Ordovician, Lower Ordovician, and Cambrian source rocks in different areas in the Tarim Basin, western China. The subgroups of aromatic hydrocarbons as well as individual aromatic compound, such as 1-MP, 9-MP, and 2,6-DMP from Cambrian-Lower Ordovician section show more depleted 13C distribution. The δ13C value difference between Cambrian-Lower Ordovician section and Upper Ordovician source rocks is up to 16.1‰ for subgroups and 14‰ for individual compounds. It can provide strong evidence for oil sourc correlation by combing the δ13C value and biomarker distribution of different oil and source rocks from different strata in the Tarim Basin. Most oils from Tazhong area have geochemical characteristics such as more negative δ13C9-MP value, poor gammacerane, and abundant homohopanes, which indicate that Upper Ordovician source rock is the main source rock. In contrast, oils from Tadong area and some oils from Tazhong area have geochemical characteristics such as high δ13C9-MP value, abundant gammacerane, and poor homohopanes, which suggest that the major contributor is Cambrian-Lower Ordovician source rock.

Geochemical Characterization of Released Bound Biomarkers by Catalytic Hydropyrolysis of Ordovician Source Rock from Tarim Basin, China

The Salgan and Yingan shales in the Keping area are Middle and Upper Ordovician hydrocarbon source rocks in the Tarim Basin, north-western China. Complete distribution of n-alkanes and isoprenoids can be obtained from the source rocks, while general terpanes ( m/z 191) and steranes (m/z 217) were totally absent. Therefore, kerogens in these rocks were further treated by catalytic hydropyrolysis (HyPy) to obtain more biomarker information. As an efficient technique, Hypy successfully released bound terpanes and steranes. Furthermore, some maturity parameters were calculated. Based on the values of these parameters, the effective Ro value of bound biomarkers in Salgan and Yingan shale was deduced to be in the range of 0.7–0.75% and 0.65–0.73%, respectively. Considering the artificial heating effect in HyPy technique, relatively lower values would be expected to the maturity of the bound biomarkers. Therefore, the incorporation of bound biomarkers into kerogen should occur even earlier, before the Ro value reached 0.65%—that is, prior to oil generation window. For both the Salgan and Yingan shales, neither high maturity nor magmatic hydrothermal effects during the Permian were responsible for the loss of free biomarkers. The simplex organic matter input dominated by acritarchs might be the possible reason for the absence of free biomarkers.

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.

The Maximum Burial Depth in Hydrocarbon Source Rocks on Kongquehe Slope in the Tarim Basin

The strata of the Kongquehe slope in the Tarim basin have suffered from long-term denudation, causing the determination of maximum ancient buried depth in mainly hydrocarbon source rocks to be very difficult. The denudation restricts the conduct of research into the hydrocarbon generation history of the source rocks. Through the use of drilling, seismic, logging, and geochemical data, calculation of the amount of denudation of the main unconformable surface, consideration of the present residual thicknesses of major hydrocarbon source rocks and other data, the authors determine maximum ancient buried depth in four major hydrocarbon source rocks and determines the time required to reach the maximum ancient buried depth. The authors have ascertained four main results through comprehensive analysis. (a) A majority of the Jurassic hydrocarbon source rock passed the hydrocarbon-generating threshold during the Neogene period and are now in the early-mature to mature stage. (b) Carboniferous hydrocarbon source rock is only distributed in the Caohu depression, having crossed the hydrocarbon-generating threshold in the Cretaceous period, and is now in the mature to late-mature stage. (c) Most of the middle-upper Ordovician hydrocarbon source rock crossed the hydrocarbon-generating threshold in the late Ordovician period and is now in the late-mature to over-mature stage. There are two blocks in the east research area that appear to contain the maximum ancient buried depth which may have experienced secondary hydrocarbon generation in the late Silurian. (d) Cambrian-Lower Ordovician hydrocarbon source rock is in the late-mature to over-mature stage and may have experienced secondary hydrocarbon generation in the Cenozoic period in most of Kongquehe area.

Ternary Diagram of Fluorenes, Dibenzothiophenes and Dibenzofurans: Indicating Depositional Environment of Crude Oil Source Rocks

Fluorene (FL), dibenzothiophene (DBT) and dibenzofuran (DBF) and their alkylated homologues are important polycyclic aromatic compounds in crude oils and source rock extracts. They share the similar chemical structure and may have genetic relationships. The parent compounds (unsubstituted), methyl-, dimethyl- and ethyl-substituted isomers are identified by comparison with retention indices reported in literatures and correlation with co-injection of internal standards in gas chromatography-mass spectrometry (GC-MS) analysis. Therefore, their relative concentrations can be determined. Based on the large data sets, this paper preliminarily establishes a ternary diagram to interpret the depositional environment/lithology for oils and related source rocks. Five typical depositional environments/lithologies are distinguished on this ternary diagram. Data points from typical marine carbonate, fluvial/deltaic/fresh lacustrine shale and swamp fall into the DBTs, FLs and DBFs end-members, respectively. Oils from marine shale have subequal contents of FLs and DBFs and lie between the zones of fluvial/deltaic/fresh lacustrine shale and swamp, but have a little higher abundance of DBTs. The oils from brackish/saline lacustrine have intermediate contents of DBTs with a wide variety and some degree overlap with that of marine shale. On the basis of the ternary diagrams, two petroleum systems in the cratonic region of the Tarim basis are defined. The majority of discovered oils were derived from the Middle-Upper Ordovician carbonate source rocks. Whereas, some oils from wells TD2, T904, LK1 and TZ62 originated from the Cambrian and Lower Ordovician source rocks. Therefore, the ternary diagram of FLs, DBTs and DBFs is a useful method to interpret depositional environment/lithology for oils and related source rocks and to definite petroleum systems as well.

Identification of the Kukersite-type source rocks in the Ordovician Stratigraphy from the Tarim Basin, NW China

Due to the importance of the Gloeocapsomorpha Prisca (G. prisca)-enriched source rocks, which belong to Kukersite-type source rocks in the Lower Paleozoic Ordovician strata, it has received great attentions during the petroleum exploration as to whether there are the Kukersite-type source rocks developed in the major hydrocarbon source strata of the Upper and Middle Ordovician in the Tarim Basin. Using pyrolysis-gas chromatography-mass spectrography to analyse kerogens from source rocks in the lime- mud mound with moderate maturity, study reveals that there are the Kukersite-type source rocks in the Ordovician strata of the Tarim Basin. The pyrolysis products showed a low content of >n-C19 normal alkanes with a significant odd-even predominance between n-C13 and n-C17, long-chain alky substituted alkylbenzene and alkylthiophene isomers and distinctive distribution of 5-N-alkyl-1, 3-Benzenediol and its homologous. Based on the geographic environment characteristics of G. Prisca, the molecular distributions of crude oil from the Lower Paleozoic petroleum systems in the Tarim Basin and characteristics of kerogen pyrolysis products from the Middle and Upper Ordovician source rocks, the results suggested that it is less possible to develop the G. Prisca-enriched Kukersite-type source rocks in the major hydrocarbon source rocks in the Middle and Upper Ordovician strata in the Tarim Basin. However, the benthic macroalga and planktonic algae-enriched source rocks are the main contributors.

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.