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A series of experiments, including natural gas molecular composition, carbon isotope analysis and fluid inclusion petrography and microthermometry were conducted to research the origin and formation of natural gases in the Middle Ordovician Yijianfang Formation and the Middle-Lower Ordovician Yingshan Formation, Gucheng-Shunnan block. Natural gases consist predominantly of methanes, with dry coefficients of 0.951–0.999 and have relatively heavy carbon isotopic signatures, with average δ13C1 and δ13C2 values of −36.4‰ and −32.5‰, respectively. The diagrams between δ13C-C1 versus C1/(C2 + C3) and methane carbon isotope versus ethane-propane isotopic separation suggest that these gases are oil-associated thermogenic gas from type Ⅱ kerogen with high thermal evolution extent of the source rocks. The empirical correlation of ln(C1/C2) and ln(C2/C3) indicates natural gases originated from crude oil cracking. Natural gases in the Gucheng block and the Shunnan block have properties similar to those of oil-cracking gases in the Eastern Lungu block and the Eastern Tazhong block. Due to reservoir temperatures being lower than formation temperatures of the gases and the potential of higher mature source rock being almost exhausted, natural gases originated predominantly from the cracking of deep paleo-oil pool rather than dispersive dissoluble organic matter in the source rocks. The comprehensive analysis of thermal evolution history, burial history, fluid inclusions and geological conditions suggest that natural gases formed during Himalayan stage. Deep oil-cracking gases accumulated in the Ordovician reservoir through migration along faults. Therefore, deep-seated natural gases have great potential for exploration.

There are many oil and gas fields around the world that are sealed by tight carbonate caprocks. Compared with gypsum rocks and shales, tight carbonate caprocks are characterized by brittleness and ease of structural fracturing and dissolving in acidic groundwater. The breakthrough pressure (BP) is a significant indicator that indicates the sealing capacity of the caprocks. Therefore, we conducted a series of experiments, including effective porosity, permeability, casting thin-sections, BP, mineral composition, microstructural characteristics and clay minerals contents on carbonate samples from Ordovician system in the Kalpin area, Tarim Basin, China to research factors that affect the BP of carbonate caprocks. According to the experimental data analysis, the BP deceases with macropore proportions and increases with proportions of micropore and mesopore volume. Due to the large macropore proportion and low clay content (

Source rocks are found in the Eocene Liushagang Formation (El1: bottom, El2 and El3:top members), in the Weixi'nan sag, Beibuwan Basin. The source rocks are mainly mudrocks, except El2, which consists of organic-rich shales at the bottom and mudrocks in the middle-upper part. Total organic carbon (TOC) and Rock-Eval analyses of 146 samples indicate that El2 rocks have the best hydrocarbon generating potential, especially for organic-rich shales that contain up to 10% TOC with HI > 800 mg/g. The vitrinite reflectance analysis suggests that El source rocks are marginally mature to mature. Geochemical analyses were conducted on 18 El rock extracts and 18 oil samples from the WZ12 field. El2 and El3 source rock have similar organic facies and are distinct from El1. El2 and El3 have higher C27 βα (20R + 20S) diasteranes/C27 αββ (20R + 20S) steranes (C27DiaS/C27S), Gammacerane/Hopane (G/H) and (C28 + C29) tricyclic terpane/((C28 + C29) tricyclic terpane + Ts) (ETR), and low C23 tricyclic terpane/hopane (C23/H) and C24 tetracyclic terpanes/C26 tricyclic terpane (C24/C26). These biomarker distributions indicate that El2 and El3 rocks were deposited under more alkaline-saline environment and had less import of terrestrial organic matter relative to El1. El2 can be distinguished from El3 as having higher 4-methylsteranes/C29 ααα steranes (4MSI) and G/H. WZ12 oils all exhibit similar compositions and display biomarker characteristics that correlate with the El2 and El3 rock extracts. 1D thermal and burial history model shows that El2 and El3 began to generate a great deal of hydrocarbon at ∼11.5 Ma and 23 Ma, respectively. At this stage, traps formed and faults actively extended downwards into the El2 and likely into El3. Oils expelled from El2 and El3 migrated upward into shallow intervals along faults then laterally along the structural slopes and accumulated in areas with good fault sealing primarily in the Miocene age Nx and Nj strata. Meanwhile, under the effect of overpressure in the middle of organic-rich shales, oils from El2 may have migrated downward into reservoirs in the upper part of El3. Lithologic traps in El1 reservoir may be charged with relatively immature oil derived from El1.

The types of organic-matter (OM) pores in shale gas reservoirs were comprehensively investigated from the Wufeng-Longmaxi (W-L) mudstones in the Changning gas field, southern Sichuan Basin, China. The aim of this research is to provide the origin and significance of OM pores development in the nanometer-scaled pore structures within shale rocks. To understand the contribution of OM pores development to the W-L mudstones, the thin-section, OM extract from bulk cores, mineralogy, pore size distribution, and image analyses by scanning electron microscopy (SEM) and atomic force microscopy (AFM) were comprehensively carried out. Combining SEM photographs and AFM observations, two types of OM pores were identified, including structural OM pores and non-structural spongy OM pores. Through organic petrology analyses, the structural OM pores evolve from telalginites mainly sourced from phytoplankton and acritarch, while the non-structural spongy OM pores are derived from bacteria, benthic algae and certain graptolites. Three basic lithofacies were observed in the first member of the W-L shales, based on the results of the low-pressure N2 adsorption. We did not find any complex interaction between mineralogy and OM pores evolution. However, siliceous shales generate the most amount of bitumen which is the main OM pores producer, and the rigid siliceous particles can make the shelter of bigger OM pores. OM pores connectivity therefore increases within the siliceous shales. OM pores development, especially structural OM pores, has a crucial effect on shale gas exploitation.

Source rocks in Lower Cambrian (Є1) and Middle-Upper Ordovician (O2+3) have low S2 values, ranging from 0.01 to 0.34 and 0.01–5.95 mg HC/g Rock, respectively. The averages of TOC are 1.07% and 0.84% for Є1 and O2+3 source rocks, respectively. The equivalent vitrinite reflectance values (VREs) indicate that Є1 rocks are in a high-over mature stage for oil generation, and O2+3 rocks are sufficiently mature. Four oil seepages from the Yingshan Formation in the Qingsong quarry of the Aksu area and 34 core samples from Є1 and O2+3 rocks in the Kalpin area were analyzed for stable carbon isotopes. Moreover, 4 oil seepages and 16 core samples were analyzed by gas chromatography-mass spectrometry (GC-MS). Compared with O2+3 rocks, Є1 rocks are characterized by lower values of Gammacerane/C30 hopane (G/H), C28/(C27 + C28 + C29) 20R ααα sterane (C28%), C29/(C27 + C28 + C29) 20R ααα sterane (C29%), C26 20S/C28 20S triaromatic steroids (C26/C28), (C26 + C27)/C28 triaromatic steroids and (C26 20R + C27 20S)/C28 20R triaromatic steroids, and higher values of C21/C23 tricyclic terpane (C21/C23), C27/(C27 + C28 + C29) 20R ααα sterane (C27%), and C35 αβ (22R + 22S) homohopane/αβ C30-hopane (C35 H/H). The two sets of source rocks have a ‘‘V (C27>C28 C34 25-norhopanes (NHs) indicates that the degree of degradation of oil seepages falls at approximately PM 6, rendering many biomarker parameters ineffective for oil-source correlations, except for triaromatic steriods and carbon isotopic compositions. The values of C26/C28, (C26 + C27)/C28 triaromatic steroids and (C26 20R + C27 20S)/C28 20R triaromatic steroids using 0.50, 1.45 and 1.80 as threshold values, respectively, can differentiate Є1 and O2+3 rocks, and oil seepages show a natural affinity to the Є1 source rocks. The Є1 rocks have lighter δ13C of kerogen and heavier δ13C of group compositions than those of O2+3 rocks. The group compositions of oil seepages are depleted in 13C by approximately 0–1.5‰ compared with kerogens of Є1 extracts, further suggesting that the oil seepages are comparable to Є1 source rocks consistent with the results of biomarker analysis.

Carbonate rocks are important targets of hydrocarbon exploration in the Gucheng area, Tarim Basin. In this study, the thin sections, carbon and oxygen isotopes, trace elements and rare earth elements of 25 carbonate samples from the Upper Cambrian and the Ordovician are conducted to research the original sedimentary environment of these carbonate rocks. The carbonate rocks have undergone high-temperature hydrothermal activity due to the movement of magmatic water in the Permian based on carbon and oxygen isotope and Euanom data. The Upper Cambrian and Ordovician are divided into five third-order sequences based on carbon isotopes and natural gamma-ray spectral logging combined with previous researches. The SQ1~SQ3 in the Upper Cambrian and Middle-Lower Ordovician predominant in sea-level decline cycle, whereas the SQ4 and SQ5 in the Middle-Upper Ordovician are dominated by sea-level rise cycle. Ceanom and Z values are suitable to analyze the redox environment and paleosalinity quantitatively, which suggests an oxidizing and marine origin in this area. The dolomites are formed in a paleoenvironment with a higher salinity, a stronger oxidation and a lower falling sea level than that of the limestones.

Knowledge of supercritical methane adsorption behavior in shales is crucial for evaluations of total shale gas-in-place (GIP) resources in deep formations. The primary object of this study is to establish an optimized model for the adsorption of supercritical methane in shale. An adaptive L-SDR model, which is a modification of the supercritical Dubinin–Radushkevich (SDR) model in combination with the Langmuir model, was introduced to interpret the measured absolute adsorption isotherms. A series of shale gas high pressure methane adsorption isotherms were measured at 303.15 K for Mesozoic shale collected in the Kuqa Depression of the Tarim Basin. In addition, published methane adsorption data on Posidonia shales were also investigated. The absolute adsorption results were fitted using the Langmuir, SDR and L-SDR models, and the accuracy of each model was analyzed and compared using an average relative error analysis. It was found that the L-SDR model can improve predictions of supercritical methane adsorption compared with predictions from the Langmuir and SDR models at both low and high temperatures, and the results indicate that this model can effectively model supercritical methane adsorption on shale. The individual contributions of the Langmuir and SDR models to the overall adsorption capacity were investigated at multiple temperatures, and the results showed that the contribution of the Langmuir model became more significant with increasing temperatures.

Numerous deep oil and gas reservoirs have recently been discovered in the Kelasu-Yiqikelike structural belt of the Kuqa Depression in the northern Tarim Basin, north-western China. The sources and accumulation processes of the oil and gas are determined in this study through a series of biomarker geochemical parameter analyses and fluid inclusion analyses, respectively. The geochemical parameters show that the oil of the Kela 2 gas field originated from the Triassic Huangshanjie (T3h) Formation lacustrine source rock and that the oil of the Jurassic reservoirs in the Dibei gas field was sourced from Jurassic coal measures, with some contribution from the T3h source rock. Furthermore, the gas in the Kela 2, Keshen and Dibei gas fields was derived from the Jurassic coal measures. Based on petrographic and fluid inclusion analyses, combined with a reconstruction of the reservoir burial history, timing estimates and charge models of the hydrocarbon accumulation have been obtained. Two stages of oil charging and one stage of gas charging were identified in the Kela 2 gas field. The two stages of oil charging occurred in the middle–late Miocene and in the early Pliocene. The gas charge occurred in the middle–late Pliocene. Additionally, one stage of gas charging occurred in the Keshen gas field in the late Pliocene to Quaternary. In contrast, two hydrocarbon charging stages were identified in the Dibei gas reservoirs, with the first occurring in the early Miocene and the second occurring in the Pliocene.

Deep carbonate reservoirs with great resource potential are key areas for future hydrocarbon exploration with the continuous innovation of deep hydrocarbon accumulation theory and technology. Breakthrough pressure (BP) is the most important parameter used to indicate rock sealing. In this study, X-ray diffraction, CO2 adsorption, N2 adsorption, high-pressure mercury injection, thin section analysis, effective porosity-permeability and BP experiments are conducted to research pore-throat characteristic of carbonate rock and the influencing factor of BP. Pore volume increases with the specific surface area (SSA) of micropore, and has a weak negative and positive correlation with the SSA of mesopore and macropore, respectively. The BP increases with an increase in the micropore proportion and decreases with an increase in the macropore proportion. Compared with R50 (the pore-throat radii corresponding to these mercury saturation of 50%), R35 (the pore-throat radii corresponding to these mercury saturation of 35%) has a better correlation with porosity and permeability and can better characterize the influence of pore throats on the sealing performance of carbonate rock. A low clay content perhaps leads to an inapparent interrelation between clay content and BP. Because of high brittleness of quartz, an increase in quartz content will cause an increase of porosity and permeability, and a decrease in BP. The BP decreases with the increase in effective porosity and permeability, and linear correlations exist among the reciprocal of porosity (A), the −0.407 power of permeability (B), and the BP. The BP calculation formula is fitted based on A and B by the principal component regression (PCR) method of SAS software for carbonate rock in the Ordovician of the Gucheng area.

The gas reservoir in the Keshen structural belt, Kuqa depression, Tarim Basin, Xinjiang, China is a typical deep and ultra-deep structural faulted anticline tight sandstone gas reservoir. This reservoir possesses abundant natural gas and exhibits a promising exploration and development prospective. However, the effectiveness of the gas migration (preferred migration pathway) and the contribution of gas source faults as a dominant migration pathway remains to be further investigated. Therefore, this paper examines gas-source correlation to determine the source of natural gas and uses fluid potential analysis combined with the tracer results of geochemical parameters to predict the predominant migration and accumulation pathways of natural gas. Next, the paper determines the contribution of gas source faults to the formation of the gas reservoir during the migration process by making a quantitative assessment of the gas source faults. The results show that the predominant source of natural gas from the deep and ultra-deep tight sandstone gas reservoir in the Keshen structural belt, Kuqa depression is Jurassic and Triassic source rock. Structural units with relatively low fluid potential represent the predominant migration pathway of natural gas. Gas source faults provide the predominant natural gas vertical transport pathway, with differences observed between zones in the south and north. The greater the contribution provided by a gas source fault during transport is, the higher the accumulation that results. The effectiveness of the natural gas migration deep and ultra-deep tight sandstone gas reservoir in the Keshen structural belt, Kuqa depression is as follows: Kela2 trap > Keshen6 trap > Keshen8 trap > Keshen2 trap > Keshen13 trap > Keshen9 trap. This method can be used in effective evaluation of the gas migration under the similar tectonic settings and reservoir formation conditions.

The Tazhong Low Rise has abundant hydrocarbon resources in the Yingshan Formation of Lower Ordovician, where dolomite has been demonstrated to be a significant target for carbonate hydrocarbon exploration. Using optical observation and geochemical tests, three types of dolomite can be used as replacement and cement products. D1 dolomite is silt or fine crystalline, and has the fluid inclusions of low Th (71.4 °C) and corresponding salinity (9.89 wt% NaCl). In addition, geochemical data indicate that D1 dolomite was formed with shallow burial fluids and was intensely affected by weathering karst in the middle Ordovician, which served as a mixing-zone for dolomitisation. D2 dolomite of medium-coarse grain has similar geochemical characteristics as D1 dolomite except that it has higher diagenetic temperature and negative δ18O, suggesting that it generally developed in a deep burial environment. The cathodoluminescence showed two zonal structures in D1 dolomite, while at least three zonal structures in D2 dolomite were influenced by multiple burial diagenetic fluids. The D3 dolomite has a saddle structure with medium-coarse crystalline, high contents of Mn, Ba, Fe, and Sr, high Th (140 °C), high salinity (20.36 wt% NaCl), and negative δ18O (–10.1 to–7.8‰). Meanwhile, D3 dolomite is distributed near faults and fractures that are accompanied by hydrothermal minerals and is obviously influenced by hydrothermal fluids.

Shale gas is an important unconventional energy source that has great potential for exploration and development. The Tarim Basin is the primary gas-producing basin with abundant shale gas resource in western China. Rock pyrolysis analysis, rock quantitative analysis, helium porosity measurements, scanning electronic microscope image analysis and isothermal adsorption tests at 30 °C were performed on outcrop samples of continental Mesozoic shales from the Kuqa Depression to determine the methane adsorption of the shale and its influencing factors. The methane adsorption capacity varied greatly in shales of different ages. Specifically, the maximum methane adsorption capacity of the Triassic shale was 0.74–4.71 mL/g and averaged 1.56 mL/g, whereas the maximum methane adsorption capacity of Jurassic shale was 1.12–14.7 mL/g and averaged 4.82 mL/g. The carbonaceous shale had high methane adsorption capacity. The methane adsorption capacity increased with increasing total organic carbon, and the free hydrocarbon content was negatively correlated with the maximum methane adsorption capacity. There was a positive relationship between the maximum methane adsorption capacity and the organic maturity in the Jurassic shale, but no correlation was observed in the Triassic shale. This lack of correlation suggests a variation in the influence of maturity on the methane adsorption in shales of different ages. There was no relationship between the clay mineral content and the maximum methane adsorption capacity, which indicates that the clay mineral content did not affect methane adsorption. The porosity had a nonlinear negative correlation with the maximum methane adsorption capacity in the Jurassic shale. The porosity of the Jurassic shale is primarily controlled by intragranular and dissolution pores in brittle minerals, and the dissolution pores provide space for free gas but contributed less to the increase in the specific surface area.

Tracing petroleum migration pathways for petroleum exploration in a sedimentary basin is challenging. Paleo-uplifts are generally considered to represent the primary migration directions of petroleum. Here we propose a model for the Kuqa Foreland Basin, in which petroleum migrates along the axes of synclines between paleo-uplifts, based on an integrated analysis of seismic, geochemical, and production data. Interpretation of detailed seismic data indicates that petroleum is unlikely to migrate to the paleo-uplifts because of their relatively low positions, fault disruptions, or a lack of Mesozoic reservoirs. Geochemical parameters, including the ratios of alkyl dibenzothiophenes and the gas wetness parameter, show that petroleum maturity gradually decreases along the axes of synclines between paleo-uplifts from northeast to southwest. Petroleum production data and gas/oil ratios also show decreasing trends from northeast to southwest. This evidence suggests that petroleum is likely to migrate along the axes of the synclines between the paleo-uplifts from northeast to southwest. This study not only enhances the scientific understanding of secondary migration, but also may be useful to guide petroleum exploration in the southern Kuqa Foreland Basin.

There are many examples of oil and gas reservoirs throughout the world that have tight carbonate rock as the caprock. These oil and gas reservoirs are often vertically overlapped (with multiple oil and gas sections) and laterally connected (to many oil and gas reservoirs). The closure of carbonate caprock is affected by many factors, such as the clay content, differential diagenesis and layer thickness. As evaluation parameters, the clay content can be determined by a gamma ray well-logging curve; the differential diagenesis is reflected in filling effects, rupture effects, cement composition and content and can be measured through the displacement pressure; the layer thickness can be obtained from drilling and well-logging data. In different regions or different members, the factors and parameters to be considered or evaluated for the closure are dependent on actual geological conditions. In this study, the clay content, displacement pressure and layer thickness were analysed, determined, calculated and normalized to generate an overall closure evaluation index (λ) for the caprock in wells on Ordovician Liang 3–5 mud-bearing limestone members on the northern slope of the Tazhong uplift. On the plane distribution map, the area with λ ≥ 1 was effectively sealed. The tight carbonate in the inner Yingshan Formation (with high-resistivity, referred to as a high-resistivity layer) was also effectively caprock. Regardless of whether it can seal oil and gas, the sealing capacity mainly depends on the displacement pressure difference between the high-resistivity layer and the underlying carbonate reservoir. Based on drilling results and the comparison of the displacement pressure difference between the two layers (by actual measurements and calculations), we observed that when the pressure difference is more than 1.95 MPa, it is an effective caprock.

There are many structural buried hills in the east of Tazhong Low Rise that have significantly valuable for oil/gas exploration and research. In this work, geochemical and geological methods were used to research the complicated diagenetic process of Yingshan carbonate. The Yingshan carbonate underwent four diagenetic stages with three types of calcite, which diagenetic environment was complex and variable. During the Early Ordovician of syndiagenetic stage, the high-magnesium CI calcite develops along the micro-fracture and has no or very weakly cathodoluminescence color. In the following early diagenetic, the Yingshan carbonate subsided and developed the CIII calcite along the corroded fissure and pressolved sutures. After the M1 buried hill formed during the Late Silurian, the Yingshan carbonate experience the supergene stage, and suffered the weathering and denudation for a long period. During the Carboniferous karst, two cave horizons developed in the M1 buried hill, corresponding with two sets of Carboniferous carbonate rocks by the stratigraphic correlation. The cement CII calcite contains less Sr, Na, Mg, and more Mn and Fe than sea water, showing bright red in the cathodoluminescence. During the following middle and late diagenetic stage, M1 buried hill underwent a process of persistent burial and slight uplifting with CIII calcite cementing from the formation water. During the Permian, the hydrothermal fluid intensely influenced the buried hill, leaving the hydrothermal minerals.

Hydrothermal dolomitization is an important diagenetic process that affects the quality of carbonate reservoirs. While geochemical modeling is a useful tool to improve our understanding of this process, comparatively little research has been focused on producing reservoir intervals. This study examines deeply buried (over 4500 m deep), Lower Ordovician dolomitized limestones (more than 50 m revealed by the borehole) in an exploration well in the Tazhong Uplift, Tarim Basin. The well penetrated a fault zone that was affected by extensive hydrothermal activity during the Permian. Batch geochemical modeling and reactive transport modeling (RTM) were used to evaluate the potential sources of hydrothermal fluid and the associated mechanisms that resulted in a relatively restricted distribution of dolomitization in the study area. Simulation results show that the RTM, which can include geological heterogeneity, provides more reliable constraints for the volume of hydrothermal fluids required for the observed scale of dolomitization, compared to batch geochemical modeling. According to the simulation results, the interstitial fluids released from underlying Cambrian formations due to high pressure and high temperature are not the only source of hydrothermal dolomitization. Other mechanism like long-lasting recharge of seawater-derived basement brines may be took place. Scenario simulations also indicate that the patterns of hydrothermal dolomitization and porosity distributions are strongly related to permeability heterogeneity in the formation. This study shows the ability and feasibility of geochemical modeling as a tool to quantitatively evaluate and further understand hydrothermal dolomitization processes, which are also helpful for other similar geological process research. However, reliable and detailed geological information, geological constrains, especially geological heterogeneity distributions, are crucial to achieve beneficial conclusions.

A promising quantitative method is the use of fluctuations of seawater silicon isotope compositions (δ30Siseawater) to estimate the silicon cycle and silicon isotopic budgets of both the marine and terrestrial systems in a pre-diatom ocean. However, a thorough global calibration of Phanerozoic δ30Siseawater, which is linked to continental tectonics and silicate weathering, has not been established. The silicon and oxygen isotope compositions of Darriwilian cherts (δ30Sichert and δ18Ochert, respectively) have considerable potential as proxies for δ30Siseawater and sea surface temperatures (SSTs), which can expand our understanding of the influence of continental tectonics and temperature changes on the Great Ordovician Biodiversification Event (GOBE). In this study, primary depositional and early diagenetic cherts were sampled from bedded chert, lump-shaped chert, nodular chert, and banded chert from five Darriwilian outcrops in the Kalpin and Yijianfang areas of the Tarim Basin in China. The preservation conditions of these cherts were assessed based on petrographic criteria such as the absence of calcite veins and fractures under macroscopic observation and the absence of aggregate chalcedony (CHA), microquartz (MQ), and cryptocrystalline quartz (MQC) using optical microscopy and scanning electronic microscopy (SEM). The SSTs and δ30Siseawater of Darriwilian seawater were reconstructed using the δ18Ochert and δ30Sichert of well-preserved cherts. Our results show that the SSTs were approximately 32 ± 5 °C in the early Darriwilian and approximately 30 ± 5 °C in the late Darriwilian. The δ30Siseawater was approximately +3.1‰ in the Kalpin and Yijianfang areas during the Darriwilian Stage. This is the first estimation of δ30Siseawater in the Darriwilian Stage, which provides a parameter for the global calibration of the δ30Siseawater of the pre-diatom ocean in the Phanerozoic Eon and validates the hypothesis that the pre-diatom ocean waters had higher δ30Si values than modern seawater.

The importance of transverse faults in basin evolution and petroleum geology has been often emphasized. However, the transverse faults in the Kuqa Foreland Basin, the most important gas producing area in China, have rarely been studied. Interpreted seismic sections and earthquake focal mechanism solutions, as well as other geological and geophysical data, allow us to identify a few widely-spaced, approximately NS trending, transverse strike-slip faults separating major structural units, and to clarify the geometry and kinematics of these transverse faults hidden below thrust faults. In the Kuqa Foreland Basin, two major structural domains can be distinguished. Transverse faults in the northern Kuqa Foreland Basin are mainly NNE trending sinistral, indicating clockwise-rotation of fault-bounded blocks. In contrast, the predominant NW trending dextral faults in the southern Kuqa Foreland Basin imply counterclockwise-rotation of fault-bounded blocks. We propose a tectonic model in which crustal blocks are bounded by strike-slip faults in a zone of simple shear rotation about vertical axis. The strike-slip faulting and thrust faulting in the Kuqa Foreland Basin suggest that some of the convergence between South Tianshan and Tarim blocks may have been accommodated not only by obvious crustal shortening and thickening along thrust faults, but also by rotation and possible lateral movement of the crust along transverse faults. Controlled by the remote collision of Indian block with Eurasian block since the Miocene, these reactivated substratum faults, which may inherit from Paleozoic deformation, control various elements relevant to gas accumulation in the Kuqa Foreland Basin which should expect to be paid more attention in the future. These elements include maturity of Tertiary and Jurassic source rocks, a difference in the regional cap of Kumugelimu salt beds from east to west, reservoir bed properties, gas migration channels, and traps formation. In addition, the strike-slip faulting of the transverse faults may affect deformation of the sedimentary cover, including making the western Qiulitag structural belt to form an arcuated structure curved to the SSW.

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 & Sons, Ltd.

The Kuqa foreland thrust belt of the Tarim Basin hosts a prolific hydrocarbon system. The main reservoirs are characterized by tight sandstone with low-porosity and ultra-low permeability, buried presently at more than 5000 m depth. Natural fracture systems have a significant impact on reservoir performance, and it may form paths for fluid flow in tight sandstone reservoirs, and therefore plays an essential role in controlling high production rates. With the aim of analyzing the distribution of favorable reservoir, we studied subsurface fracture patterns and petrophysical properties of the Bashijiqike Formation with data collected from Dabei structure and Keshen structure. We document the presence of four fracture systems whose distribution is related to far-field stress, thrusting and folding. In the Keshen anticlines, higher fracture intensities are observed in the limbs, with principal east-west (hinge-parallel fracture system) direction. The hinge-parallel fracture system includes a moderate-dipping fracture set and a vertical fracture set. Crosscutting relationships stress field inversion and fracture surface textures suggest that the moderate-dipping fracture set consists of shear fractures and can be explained by intra-layer shear caused by thrusting. The vertical fracture set may be formed due to the local outer arc extension during folding. The oblique fracture system shows scattering in strike, and is supposed to be related to a shear event of locally left-lateral strike-slip. Whereas, in the Dabei anticlines, the major system is hinge-perpendicular fracture system (NW-SE), showing a trending of increasing fracture intensity from limbs to hinge. The hinge-perpendicular fractures system in the Dabei anticlines consist of shear fractures and tension fractures. Stress inversion result shows it corresponds to northwest-southeast orientation compression stage. Besides, we analyzed petrophysical properties include porosity, permeability, Young's module, Poisson ratio and compressive strength of the Bashijiqike Formation concerning their structural position within folds. It indicates that the highest porosity and permeability are associated with dissolution and fracturing. The compressive strength of different structural positions also restrict the variations of mechanical properties of rocks. The best reservoir quality is suggested in the hinge zone and areas close to thrust. The findings have given maybe helpful for providing favorable reservoir targets for prospecting in the compressional basin.

A number of beach-bar sandstone reservoir beds are developed in the upper fourth member of the Eocene Shahejie Formation (Es4s) on the southern slope of the Dongying Sag. Based on the analysis of seismic and logging data, with characterization and petrographic studies of core and cutting samples, this paper analyzes the hydrocarbon accumulation characteristics in two typical blocks of the Boxing and Wangjiagang oilfields, especially reservoir bed heterogeneity and migration conditions that influence oil and gas distribution, calculates the index of reservoir bed quality (IRQ) with a mathematical method, and discusses the relationship between driving force and resistance of hydrocarbon accumulation. Taking into account the characteristics of thin interbeds in beach-bar sandstones, an experimental model simulated the characteristics of hydrocarbon migration and accumulation in thin interbedded sandstones with reservoir bed heterogeneity. The results showed that hydrocarbon distribution and properties were extremely non-uniform. Reservoir bed and migration conditions controlled hydrocarbon accumulation in beach-bar sandstones. IRQ is above 0.4 in the main hydrocarbon region. Sand body distribution, structural configuration and fault systems controlled the direction of regional migration and location of hydrocarbon accumulation. Simulation experiments indicated that the change of driving force for hydrocarbon migration affected selective accumulation mechanisms. Hydrocarbon moved vertically along fault zones to the reservoir and resulted in the distribution of hydrocarbon in the reservoir. Two kinds of hydrocarbon accumulation models exist in the study area. One is a hydrocarbon accumulation model controlled by reservoir bed heterogeneity and the second is a hydrocarbon accumulation model controlled by a complex migration system with faults connecting sandbodies. Finally, different exploration strategies should be adopted for the detailed exploration for beach-bar sandstone reservoirs according to different geological backgrounds.

Pyrite is the most common authigenic mineral preserved in many ancient sedimentary rocks. Pyrite also widely exists in the Longmaxi and Wufeng marine shales in the middle Yangtze area in South China. The Longmaxi and Wufeng shales were mainly discovered with 3 types of pyrites: pyrite framboids, euhedral pyrites and infilled framboids. Euhedral pyrites (Py4) and infilled framboids (Py5) belong to the diagenetic pyrites. Based on the formation mechanism of pyrites, the pyrites could be divided into syngenetic pyrites, early diagenetic pyrites, and late diagenetic pyrites. Under a scanning electron microscope (SEM), the syngenetic pyrites are mostly small framboids composed of small microcrystals, but the diagenetic pyrites are variable in shapes and the diagenetic framboids are variable in sizes with large microcrystals. Due to the deep burial stage, the pore space in the sediment was sharply reduced and the diameter of the late diagenetic framboids that formed in the pore space is similar to the diameter of the syngenetic framboids. However, the diameter of the syngenetic framboid microcrystals is suggested to range mainly from 0.3 &micro, m to 0.4 &micro, m, and that of the diagenetic framboid microcrystals is larger than 0.4 &micro, m in the study area. According to the diameter of the pyrite framboids (D) and the diameter of the framboid microcrystals (d), the pyrite framboids could be divided into 3 sizes: syngenetic framboids (Py1, D &lt, 5 &micro, m, d &le, 0.4 &micro, m), early diagenetic framboids (Py2, D &gt, m, d &gt, m) and late diagenetic framboids (Py3, D &lt, m). Additionally, the mean size and standard deviation/skewness values of the populations of pyrite framboids were used to distinguish the paleoredox conditions during the sedimentary stage. In the study area, most of the pyrite framboids are smaller than 5 &micro, m, indicating the sedimentary water body was a euxinic environment. However, pyrite framboids larger than 5 &micro, m in the shales indicated that the sedimentary water body transformed to an oxic-dysoxic environment with relatively low total organic carbon (TOC: 0.4&ndash, 0.99%). Furthermore, the size of the framboid microcrystals could be used to estimate the gas content due to thermochemical sulfate reduction (TSR). The process of TSR occurs with oxidation of organic matter (OM) and depletes the H bond of the OM, which will influence the amount of alkane gas produced from the organic matter during the thermal evolution. Thus, syngenetic pyrites (d ranges from 0.35 &micro, m to 0.37 &micro, m) occupy the main proportion of pyrites in the Wufeng shales with high gas content (1.30&ndash, 2.30 m3/t), but the Longmaxi shales (d ranges from 0.35 &micro, m to 0.72 &micro, m) with a relatively low gas content (0.07&ndash, 0.93 m3/t) contain diagenetic pyrites. Because of TSR, the increasing size of the microcrystals may result in an increase in the value of &delta, 13C1 and a decrease in the value of &delta, 13C1-&delta, 13C2. Consequently, the size of pyrite framboids and microcrystals could be widely used for rapid evaluation of the paleoredox conditions and the gas content in shales.

Despite the absence of regional cap rocks in the Lower Paleozoic for the entire Tazhong Low Rise, several sets of effective local cap rocks are well preserved on the Northern Slope. Of these the best is the Ordovician mudstone of the Sangtamu Formation; the second is the Silurian Red Mudstone Member of the Tatairtag Formation and the marl of the Ordovician Lianglitag Formation; and the third is the gray mudstone of the Silurian Kepingtag Formation. The dense limestone of the Ordovician Yingshan Formation and the gypsum of the Middle Cambrian have shown initial sealing capacity. These effective cap rocks are closely related to the distribution of Lower Palaeozoic hydrocarbons in the Tazhong Low Rise. With well-preserved Sangtamu Formation mudstone and its location close to migration pathways, rich Lower Paleozoic hydrocarbon accumulation can be found on the Northern Slope. Vertically, most of the reserves are distributed below the Sangtamu Formation mudstone; areally, hydrocarbons are mainly found in the areas with well-developed Sangtamu Formation mudstone and Lianglitag Formation marl. Burial history and hydrocarbon charging history show that the evolution of Lower Palaeozoic cap rocks controlled the accumulation of hydrocarbon in the Tazhong Low Rise. Take the Red Mudstone Member of the Tatairtag Formation and Sangtamu Formation mudstone for examples: 1) In the hydrocarbon charging time of the Late Caledonian — Early Hercynian, with top surfaces at burial depths of over 1,100 m, the cap rocks were able to seal oil and gas; 2) During the intense uplifting of the Devonian, the cap rocks with top surfaces at burial depths of 200–800 m and 500–1,100 m respectively were denuded in local areas, thus hydrocarbons trapped in earlier time were degraded to widespread bitumen; 3) In the hydrocarbon charging time of the Late Hercynian and Himalayan, the top surfaces of the cap rocks were at burial depths of over 2,000 m without intense uplifting and denudation thereafter, so trapped hydrocarbons were preserved. Based on cap rocks, the Ordovician Penglaiba Formation and Lower Cambrian dolomite could be potential targets for exploration on the Tazhong Northern Slope, and combined with hydrocarbon migration, less risk would be involved.

The Yingshan Formation, located on the Tazhong Northern Slope, contains oil- and gas-rich layers with the reserves of about 700 × 106 TOE. The high-resistivity inner layers isolate the hydrocarbon bearing zones and form the sequential sets of reservoir bed-seal assemblages in a vertical direction within the Yingshan Formation, which is directly bound above by a micritic carbonate cap rock that is overlain by the 3rd to 5th members of the Lianglitag Formation. The sealing capability of the cap rock and inner barrier layers was evaluated macroscopically and microscopically in terms of the core breakthrough pressure and thin-section identification. The evaluation parameters were extracted from the statistical analysis of drilling and logging data. The 3rd to 5th members of the Lianglitag Formation are more shaly, but the inner barrier layers in the Yingshan Formation are more dolomitic. Argillaceous limestone is more capable of sealing oil and gas zones than micritic limestone. The 3rd to 5th members of the Lianglitag Formation, of which the gamma ray response and core displacement pressure are greater than 20 API and 14 MPa, respectively, provide good sealing with thicknesses of more than 100 m and have better sealing with thickness of more than 200 m. For the same porosity, dolomite has lower coreflood displacement pressure than limestone. The difference in coreflood displacement pressure between the barrier layers and the underlying reservoir bed is 6 MPa, the cutoff value for sealing capability. Carbonate sealing was controlled by early sedimentation and was influenced by late diagenesis. The direct cap rock is dense and has cement content of more than 10%, up to 31%. The reservoir bed has cement content of less than 10%. Generally, the direct cap rock and the inner barrier layers are relatively stable on the lateral distribution.

Marine carbonate reservoirs, as a focus of petroleum exploration and development all over the world, are involved with high exploration risk and prediction difficulty owing to high heterogeneity and diversity of reservoir beds. In the Tarim Basin, NW China, carbonate reservoirs with resources about 38 % of the whole basin in a large prospecting area are mainly distributed in the Cambrian and Ordovician in central (Tazhong) and northern (Tabei) Tarim. Recently on the northern slope, Tazhong Low Rise, Central Uplift, Tarim Basin, a breakthrough has been made in the karsted weathering crust of Lower Ordovician Yingshan Formation and reef-flat reservoir of Upper Ordovician Lianglitag Formation. As a new frontier of exploration, oil/gas distribution and controlling factors of carbonate reservoirs in the Yingshan Formation are not clearly understood. In this work, play elements of the Yingshan Formation, such as seal-reservoir bed assemblage, oil/gas properties, and faulting, were studied by core and slice observation and field investigation. High-quality reservoir beds of Yingshan Formation are quasi-layer distributed in the interstratal karst belt about 250 m below the unconformity. The reservoir beds of fracture–void and void are formed by faulting, associated fracturing, and karstification. The Yingshan Formation is a large-scale condensate gas reservoir with partly oil. Owing to different oil–gas infilling periods, isolated pools far from the faults are primarily oil in the Hercynian; oppositely, condensate gas reservoirs near the faults are intensely influenced by gas invasion during the Himalayan movement. Laterally, oil/gas distribution is controlled by stratal pinch-out and strike-slip faults. Vertically, cap rock of the third to fifth members of the Lianglitag Formation and Yingshan interior high resistivity layers are superimposed with Yingshan reservoir beds to form several seal-reservoir bed assemblages. Oil and gas are superimposed and affected by gas invasion with characteristics of oil in the upper horizon and gas in the lower horizon.

Marine carbonate reservoirs, as a focus of petroleum exploration and development in China, are involved with high exploration risk and prediction difficulty owing to high heterogeneity and diversity of reservoir beds. In the Tarim Basin, NW China, carbonate reservoirs host about 38% of the whole basin's hydrocarbon resources in a large prospecting area mainly distributed in the Cambrian and Ordovician rocks in central (Tazhong) and northern (Tabei) Tarim. Recently, a better understanding has been made of the karsted weathering crust at the top of the Lower Ordovician Yingshan Formation in the northern slope area of the Tazhong Low Rise, Central Uplift, Tarim Basin. As a new frontier of exploration, oil/gas distribution and controlling factors of carbonate reservoirs in the Yingshan Formation are not clearly understood. In this work, we investigated the reservoir beds and oil/gas properties in 13 wells in Well block ZG-43 on the No. 10 structural belt in the Tazhong Low Rise, and studied hydrocarbon accumulation characteristics with seismic and geochemical data. The Yingshan Formation in Well block ZG-43 is mainly composed of calcarenite, dolomitic limestone, dolomite, cryptite, as low porosity and low permeability reservoir beds, with fracture-void porosity constituting the main reservoir pore space. Oil/gas is quasi-layer distributed beneath the unconformity between the Yingshan and Lianglitag formations to a depth of 140 m. The oil in Well block ZG-43 is condensate with low density, low viscosity, low sulphur, low resin, low asphaltene, and high wax. The gas is 87.3% methane, generally containing H2S. The oil/gas distribution pattern is oil in the east and gas in the west, and H2S content in the west is lower than that in the east. The controlling factors for hydrocarbon are multi-source supply and multi-phase charging, interstratal karstification, hydrothermal activity, structural location and sealing condition. A structural–lithological trap is the main type of oil/gas accumulation. Oil/gas distribution was clearly affected by strike–slip faults. Oil/gas with multi-source supply and multi-phase charging was controlled by favourable local palaeo-highs, and affected by later karsting and hydrothermal activity, as well as gas invasion in the Himalayan (Cenozoic) period. Under the caprock of compact limestone in the third to fifth members of the Lianglitag Formation, oil/gas migrated up along the strike–slip fault planes, and moved laterally to both sides in a ‘T’ shape, and formed large-scale quasi-layer condensate gas reservoirs controlled by reservoir bed quality. Copyright © 2013 John Wiley & Sons, Ltd.

The Liaozhong Sag is one of the major oil-bearing areas in offshore Bohai Bay Basin and is obviously characterized by late-stage hydrocarbon accumulation. In this paper our study was focused on strong activities of tectonic movement in the Liaozhong sag. In terms of source rock thermal history analysis, generation, migration and accumulation of hydrocarbon, late-stage hydrocarbon accumulation and enrichment pattern were summarized. Apatite fission track analysis and evolutionary history of the Easy% Ro model simulation of source rock showed that major source rocks became matured rapidly at the time 5.1Ma from the present. Fault analysis, showed that hydrocarbon migration in the study area was mainly the result of fault transportation. Fluid inclusions indicated that the accumulation period of oil and gas reservoirs was 5.1Ma from the present. Our study showed that late-stage rapid hydrocarbon generation, late-stage vertical fault transportation, hydrocarbon accumulation near source rocks and late-stage rapid in-filling are the main features of hydrocarbon accumulation in the Liaozhong Sag. The abnormal high pressure and fluid inclusion homogenization temperature anomaly are indications of late-stage episodic reservoiring and in-filling. Regional reservoir-cap rock combination of Eocene Shahejie Formation and Oligocene Dongying Formation, predominant transport channels and relevant traps formed by the complex tectonic movement of the Tan-Lu Fault are major factors controlling hydrocarbon accumulation. Episodic reservoiring of formation overpressure, near-source accumulation and fault control constitute the oil and gas enrichment pattern of the Liaozhong Sag.

Carbon isotopic compositions were determined by GC–IRMS for individual n -alkanes in crude oils and the free, adsorbed and inclusion oils recovered by sequential extraction from reservoir rocks in the Tazhong Uplift and Tahe oilfield in the Tabei Uplift of Tarim Basin as well as extracts of the Cambrian–Ordovician source rocks in the basin. The variations of the δ 13 C values of individual n -alkanes among the 15 oils from the Tazhong Uplift and among the 15 oils from the Triassic and Carboniferous sandstone reservoirs and the 21 oils from the Ordovician carbonate reservoirs in the Tahe oilfield demonstrate that these marine oils are derived from two end member source rocks. The major proportion of these marine oils is derived from the type A source rocks with low δ 13 C values while a minor proportion is derived from the type B source rocks with high δ 13 C values. Type A source rocks are within either the Cambrian–Lower Ordovician or the Middle–Upper Ordovician strata (not drilled so far) while type B source rocks are within the Cambrian–Lower Ordovician strata, as found in boreholes TD2 and Fang 1. In addition, the three oils from the Cretaceous sandstone reservoirs in the Tahe oilfield with exceptionally high Pr/Ph ratio and δ 13 C values of individual n -alkanes are derived, or mainly derived, from the Triassic–Jurassic terrigenous source rocks located in Quka Depression. The difference of the δ 13 C values of individual n -alkanes among the free, adsorbed and inclusion oils in the reservoir rocks and corresponding crude oils reflects source variation during the reservoir filling process. In general, the initial oil charge is derived from the type B source rocks with high δ 13 C values while the later oil charge is derived from the type A source rocks with low δ 13 C values. The δ 13 C values of individual n -alkanes do not simply correlate with the biomarker parameters for the marine oils in the Tazhong Uplift and Tahe oilfield, suggesting that molecular parameters alone are not adequate for reliable oil-source correlation for high maturity oils with complex mixing.

The northern slope of Tazhong palaeo-uplift has become a key target field for petroleum exploration in Tarim Basin. A major breakthrough is made in the Upper Ordovician oil and gas exploration in the west part of northern slope. Oil and gas near the Tazhong I slope-break zone occurred in Liang2 section was dominated by condensate gas reservoir, while oil reservoir was mainly inward distributed in Liang3 section. The crude oils in this region in physical properties characterized by low density, low viscosity, low freezing point, low sulfur content, medium wax content. And the natural gas in chemical components was featured by low-medium nitrogen content, low-medium carbon dioxide content and medium-high hydrogen sulfide content. In the plane direction, oil and gas exhibited a “oil in the interior, gas in the exterior” distribution pattern, and mainly located in a depth range of 0∼60 m below the top of the Liang3 section in the longitudinal direction. The distribution patterns displayed in physical properties and chemical compositions of oil and gas are controlled by multiple influencing factors. The results of above comprehensive studies suggested that vertical overriding of reef-bank-type reservoirs in Liang2 section and karst reservoirs in Liang3 section provided superior reservoir conditions; faults and fractures not only formed reservoir space and improved reservoir quality, also promoted the development of karst reservoirs and provided good migration pathway for hydrocarbon accumulation; one of the nonnegligible factors leading to this kind of distribution pattern for the Upper Ordovician oil and gas reservoirs is shale content in the compact carbonate formation; multi-sources and multi-stages of hydrocarbon filling are absolutely necessary controlling factor for this kind of distribution pattern in the whole block.

Abundant hydrocarbon shows are distributed in five different regions in the Kalpin area, northwestern Tarim Basin: Aksu hydrocarbon shows region, Subashi hydrocarbon shows region, Sanchakou hydrocarbon shows region, Piqiang hydrocarbon shows region, and Sickl hydrocarbon shows region, totaling 27 hydrocarbon show points. From the statistical analysis of all hydrocarbon shows in the study area, the paper summarizes the distribution characteristics. Combined with field investigation, previous documents of Kalpin area and oil-source correlation of hydrocarbon shows, the authors indicate that large multilayered oil-bearing paleo-reservoirs existed in the geological process in the Kalpin area, such as Aksu paleo-reservoirs and Piqiang paleo-reservoirs. Despite destruction by several periods of tectonic events after the formation of paleo-reservoirs, many reservoirs may still be left undamaged. Giant gas fields below the Middle Cambrian gypsum-salt bed could be preserved in the Kalpin area. In addition, the Middle-Lower Permian Balikelike formation, with good oil generating condition is an important exploration target in the Kalpin area.

Large-scale weathering crust karsted carbonate reservoir beds were developed in the Lower Ordovician Yingshan Formation on the northern slope of the Tazhong area in the Tarim Basin, NW China. The research on weathering crust karsted reservoir beds and faulting showed strongly heterogeneous karsted reservoir beds characterized by horizontal contiguous distribution and vertical superimposition, with fracture-hole as the main reservoir space. High quality reservoir beds were developed in the vertical seepage zone and horizontal phreatic zone, 0–200 meters below the unconformity. Reservoir bed quality of karsted carbonate rock was greatly improved by faulting, which increased the depth and size of karstification. A strike-slip fault developed over a long period in the NE direction and a thrust fault in the NW direction crossed each other, and caused distinct segmentation of the Tazhong No.1 Fault and dissection of the Yingshan Formation into multiple structural units. The strike-slip fault was the significant hydrocarbon migration pathway. Multiple hydrocarbon charging points were formed by the thrust fault and strike-slip fault, as the important fill-in of late-stage gas accumulation. Under the dual control of faulting and karstification, accumulation of hydrocarbons in the Lower Ordovician Yingshan Formation showed distinct segment-wise and block-wise features. Oil distribution is “high in the west and interior, low in the east and exterior”, while gas distribution is the opposite. The hydrocarbon play extends within 0.8–4.5 kilometers from the strike-slip fault and appeared layered vertically at 10–220 meters below the unconformity.

Molecular data from a large set of source rock, crude oil and oil-containing reservoir rock samples from the Tarim Basin demonstrate multiple sources for the marine oils in the studied areas of this basin. Based on gammacerane/C31 hopane and C28/(C27 +C 28 +C 29) sterane ratios, three of the fifteen crude oils from the Tazhong Uplift correlate with Cambrian–Lower Ordovician source rocks, while the other crude oils from the Tazhong Uplift and all 39 crude oils from the Tahe oilfield in the Tabei Uplift correlate with Middle–Upper Ordovician source rocks. These two ratios further demonstrate that most of the free oils and nearly all of the adsorbed and inclusion oils in oil-containing reservoir rocks from the Tazhong Uplift correlate with Cambrian–Lower Ordovician source rocks, while the free and inclusion oils in oil-containing carbonates from the Tahe oilfield correlate mainly with Middle–Upper Ordovician source rocks. This result suggests that crude oils in the Tazhong Uplift are partly derived from the Cambrian–Lower Ordovician source rocks while those in the Ordovician carbonate reservoirs of Tahe oilfield are overwhelmingly derived from the Middle–Upper Ordovician source rocks. The scatter of C23 tricyclic terpane/(C23 tricyclic terpane + C30 17a,21b(H)-hopane) and C21/(C21 + RC29) sterane ratios for the free and inclusion oils from oil-containing carbonates in the Tahe oilfield possibly reflects the subtle organofacies variations in the source rocks, implying that the Ordovician reservoirs in this oilfield are near the major source kitchen. In contrast, the close and positive relationship between these two ratios for oil components in the oil-containing reservoir rocks from the Tazhong Uplift implies that they are far from the major source kitchen.

There are plentiful oil and gas shows in the Eastern Tarim Basin, but this area is much less explored. Development of a hydrocarbon accumulation model could provide guidance for future exploration. With analysis of control of hydrocarbon accumulation by tectonic evolution as a main line, combined with researches on hydrocarbon source rocks, reservoirs, traps and cap rocks in drilled wells, the processes of hydrocarbon generation, migration and accumulation were studied comprehensively. Finally three patterns of hydrocarbon accumulation were established as follows: lower source-upper reservoir hydrocarbon accumulation model above the upper Ordovician, mixed source-fault transportation-common sealing hydrocarbon accumulation model of the Jurassic sandstone and self-generating-self-preserving hydrocarbon accumulation model of the lower Palaeozoic carbonatite.

The Baicheng (拜城) piggy-back basin was part of the intracontinental foreland basin system of southern Tianshan (天山) Mountains. It was formed on a thrust-and-fold belt induced by Mio-Pliocene collision between southern Tianshan Mountains and Tarim craton that controlled the thick synorogenic basin fills. Sedimentological analysis and a restored cross-section based on seismic data and field studies revealed three tectono-depositional sequences of synorogenic basin fills. (1) The Lower Miocene sequence (Jidike (吉迪克) Formation) was formed under alluvial-braided river-lacustrine environments, in response to geodynamic changes of the Kuqa (库车) fold and thrust belt from the embryonic foreland to a foredeep in the course of orogenic loading period. (2) The Upper Miocene sequence (Kangcun (康村) Formation) was developed in fluvial-delta and lacustrine environments, within a foredeep due to orogenic thrust. (3) The Pliocene sequence (Kuqa Formation) was formed in the Baicheng piggy-back basin that became a wedge-top depozone, thrusting in the Qiulitagh (秋里塔格) thrust belt that propagated progressively southward to the Yaken (牙肯) thrust belt.

The geologic conditions of superimposed basins in China are very complicated. This is mainly shown by multi-phase structural evolution, multiple sets of source-reservoir-cap rock combinations, multiple stages of hydrocarbon generation and expulsion from source rocks, multi-cycle hydrocarbon enrichment and accumulation, and multi-phase reservoir adjustment and reconstruction. The enrichment, accumulation and distribution of hydrocarbon is mainly controlled by the source rock kitchen, paleoanticline, regional cap rock and intensity of tectonic movement. In this paper, the T-BCMS model has been developed to predict favorable areas of hydrocarbon accumulation in complicated superimposed basins according to time and spatial relationships among five key factors. The five factors include unconformity surface representing tectonic balancing (B), regional cap rock representing hydrocarbon protection (C), paleo-anticline representing hydrocarbon migration and accumulation (M), source rock kitchen representing hydrocarbon generation and expulsion (S) and geological time (T). There are three necessary conditions to form favorable areas of hydrocarbon accumulation. First, four key factors BCMS should be strictly in the order of BCMS from top to bottom. Second, superimposition of four key factors BCMS in the same area is the most favorable for hydrocarbon accumulation. Third, vertically ordered combination and superimposition in the same area of BCMS should occur at the same geological time. The model has been used to predict the most favorable exploration areas in Ordovician in the Tarim Basin in the main hydrocarbon accumulation periods. The result shows that 95% of the discovered Ordovician hydrocarbon reservoirs are located in the predicted areas, which indicates the feasibility and reliability of the key factor matching T-BCMS model for hydrocarbon accumulation and enrichment.

Diverse types of marine carbonate reservoirs have been discovered in the Tazhong Uplift, Tarim Basin, and late alteration of such reservoirs is obvious. The marine source rocks of the Cambrian-lower Ordovician and the middle-upper Ordovician provided abundant oil and gas for hydrocarbon accumulation. The hydrocarbons filled various reservoirs in multiple stages to form different types of reservoirs from late Caledonian to early Hercynian, from late Hercynian to early Indosininan and from late Yanshanian to Himalayan. All these events greatly complicated hydrocarbon accumulation. An analysis of the discovered carbonate reservoirs in the Tazhong Uplift indicated that the development of a reservoir was controlled by subaerial weathering and freshwater leaching, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoir beds, the hydrocarbon accumulation zones in the Tazhong area were identified as: karsted reservoirs, reef/bank reservoirs, dolomite interior reservoirs, and hydrothermal reservoirs. Such carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift, respectively. Because of differences in the mechanism of reservoir formation, the reservoir space, capability, type and distribution of reservoirs are often different in different carbonate hydrocarbon accumulation zones.

The quality of the Ordovician carbonate reservoir beds in the Tarim Basin is closely related to the development of secondary pores, fractures and cavities. Karstification is important in improving the properties of reservoir beds, and karstification related to unconformity has caught wide attention. Compared with the recent research on the unconformity karst reservoir bed improvement, this paper shows a new way of carbonate reservoir bed transformation. Based on field survey, core and slices observation, transformation of Ordovician carbonate reservoir beds by faulting can be classified into three types: (1) Secondary faults and fracturs generated by faulting improved carbonate reservoir bed properties, which were named the Lunnan or Tazhong82 model; (2) upflow of deep geothermal fluids caused by faulting, with some components metasomatizing with carbonate and forming some secondary deposit, such as fluorite. It can improve carbonate reservoir bed properties obviously and is named the Tazhong 82 model; and (3) the faulting extending up to the surface increased the depth of supergene karstification and the thickness of reservoir bed. It is named the Hetianhe model. Transformation effect of carbonate reservoir beds by faulting was very significant, mainly distributed on the slopes or on the edge or plunging end of the uplift.

The timing of hydrocarbon charging relative to trap formation is a key factor for evaluating the exploration potential of the Qiulitagh fold and thrust belt (QFTB) on the north flank of the Tarim basin. Data obtained by this study indicate that structural traps were filled by hydrocarbons in two episodes. In this area, at least four major deformation events have been identified for the period of Late Cretaceous to Pliocene. The first event occurred in Late Cretaceous and led to the formation of paleo-uplift structures. The second event was characterized by thrust features and occurred in latest Oligocene. The third and fourth events were represented by compressional structures that were developed in Late Miocene and Late Pliocene, respectively. Based on oil and gas-source rock correlations and 1-D basin modeling, two episodes of hydrocarbon generation and migration are proposed to be responsible for oil and gas accumulations in the QFTB. The two episodes of hydrocarbon charging from a source kitchen north of the study area took place in Early Miocene and Pliocene, respectively. Since the QFTB was uplifted in Late Oligocene and Late Miocene, the hydrocarbon generated during all two periods could migrate toward this area to form oil and gas accumulations in suitable structures.

Hydrocarbon accumulation of the Silurian in the Tazhong uplift of Tarim basin is characterized by “two sources and three stages”. “Two sources” means that the hydrocarbons are derived from two source rocks of the Cambrian and Middle-Upper Ordovician. “Three stages” means that asphalt and movable oil undergoes three hydrocarbon accumulation stages, i.e., Late Caledonian, Late Hercynian, and Yanshanian-Himalayan. The formation of asphalt resulted from the destruction of the hydrocarbons accumulated and migrated in the early stages. The present movable oil, mostly derived from Middle-Upper Ordovician source rock, resulted from the hydrocarbons accumulated in the late stage. There are three types of reservoirs, i.e., anticline structural, stratigraphic lithological, and lava shield reservoirs in the Tazhong uplift. Hydrocarbon accumulation of the Silurian in the Tazhong uplift is controlled by the three factors. (1) The background of uplift structure. Around the ancient uplift, the compounding of many types makes up the composite hydrocarbon accumulation areas. (2) Effective cover. The show of oil gas including asphalt, heavy crude oil, and normal oil is quite active in the Silurian. Asphalt and heavy crude oil are distributed under the red mudstone member and movable oil is distributed under the gray mudstone member. (3) High quality reservoir bed. Sandstone is distributed widely in the Tazhong area. Reservoir pore space can be divided into three types: a) secondary origin-primary origin pore space; b) primary origin-secondary origin pore space, and c) micropore space. Porosity is 3.3–17.4%, and permeability is (0.1–667.97) × 10 −3 μm 2 .