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The recent gas exploration in West China demonstrated that formation conditions of tight‐sandstone gas are distinct from typical ones in North America. One remarkable difference is that complicated tectonic conditions in the foreland basin of West China, especially the Himalayan tectonic movement, resulted in widely developed fractures in tight‐sand reservoirs. Thus, this work employed dual media to characterize tight‐sand reservoir system and explain the impact of dual media on tight‐sand gas reservoir by: (a) describing the feature of fractures and properties of Yinan 2 tight‐sand reservoir; (b) characterizing dual media with mercury intrusion porosimetry, full diameter and conventional core analysis; (c) discussing gas charging and accumulating in dual media based on the difference between dual media and tight‐sand rocks. Observation from cores, FMI images and thin sections suggested that macro‐ and micro‐fractures are widely distributed in Lower Jurassic Ahe Formation (J1a) tight sandstones, with dip angle of 70° to 80°. These fractures are strongly scale‐dependent with length of several centimetres to a few tens of centimetres and apertures of several hundreds to several thousands of microns. J1a tight‐sand reservoir is characterized by poor porosity, with an average value of 7.7%, whereas measured permeability varies from 0.01–100 mD. Intrusion and extrusion curves of dual media and tight‐sand rocks are significantly different from each other, while displacement pressure and medium saturation pressure of dual media are lower than tight‐sand rocks. Importantly, maximum pore throats of dual media are 1.75–32.22 times larger than juxtaposed tight‐sand rocks. The ratio of permeability between dual media and tight sandstone is up to 1,000, whereas the ratio of porosities only ranges from 1 to 1.5. Thus, dual media in tight‐sand reservoir represents high permeability system and matrix pores are primarily storage system. The impact of dual media on tight‐sand gas reservoir involves its position, temporal coupling of gas charging and growth. In terms of fracture growth prior to gas charge, multi‐force can work together as a driving force, and fractures as a flow system and matrix pores as a storage system linked by fractures; buoyancy is the primary driving force in fractures. In terms of gas charge prior to fracture growth, dual media can also exert a positive impact on gas charging when occurring in the inner part of tight‐sand reservoir defined by the critical throat threshold. However, dual media can also destroy the "inverted gas–water" and shrink tight‐sand gas reservoir when occurring at the original critical throat threshold. [ABSTRACT FROM AUTHOR]

The Tarim Basin in China is a complicated superimposed basin with four periods of hydrocarbon accumulations and three periods of modifications due to tectonic movements, forming complicated hydrocarbon reservoirs, many of which have gone through reservoir migration, reservoir scale reformation, reservoir damage and phase alterations a result of the tectonic events. Due to the complexity, the hydrocarbon exploration in this region has low success drilling rate. It is of great importance to study the destruction to the early hydrocarbon accumulations by the tectonic movements and quantitatively evaluate the remaining resource for understanding the current hydrocarbon distribution and guiding the exploration. This study analyzed six periods of large tectonic events in the Tarim Basin, and found the destroyed hydrocarbon volume was mainly controlled by four geological factors, including the ratio of the destroyed to the original hydrocarbon amount, tectonic event number and sequence, and the cap seal capacity. Larger ratio of destroyed hydrocarbon, less tectonic event number, later sequence and stronger cap seal capacity lead to more hydrocarbons preserved through the tectonic events. Based on the geological analysis, we established quantitative relationships among the destroyed hydrocarbon volume by the tectonic events (Q l ), the volume of primary hydrocarbon accumulation (Q 0 ), the ratio of destroyed hydrocarbon (K l ), the tectonic event number (n) and sequence (i), and cap seal capacity (fc). Using these relationships and the calibrated geological parameters, we delineated the hydrocarbon accumulation and destruction history and quantified the hydrocarbon loss due to the tectonic events for both the Tazhong area and the whole Tarim Basin. In the Tazhong area, four major accumulation events occurred at 510 Ma, 298 Ma, 227 Ma and 38 Ma with each accumulation underwent 68%, 59%, 28% and 0% of hydrocarbon loss due to later tectonic events. In total, over 60% of the original hydrocarbon reserves have been destroyed in the Tarim Basin, with an estimate of ca. 1.9 billion tons remaining hydrocarbons in the Tazhong area. At present, more than 95% oil and gas reservoirs and over 93% high quality exploration wells are located in the areas with high remaining resource potential predicted in this study, whereas 70% non-commercial production wells are located outside. Overall, this work shows that a careful evaluation of the damage to reservoirs from tectonic events can considerably enhance the success rate of hydrocarbon exploration. [ABSTRACT FROM AUTHOR]

Understanding hydrocarbon migration mechanism is a key scientific problem that needs to be resolved for effective hydrocarbon exploration in the Ordovician rocks of the Tazhong area, Tarim Basin. Based on analyses of geological setting and reservoir distribution characteristics, hydrocarbon migration process, and mechanisms in the Ordovician, Tazhong area, were investigated by integrating geological, geophysical, and geochemical parameters. Successfully analysed parameters included logging reservoir properties, seismic attributes, production outputs, fluid properties, and hydrocarbon maturity parameters. Results indicate that hydrocarbons were introduced into the Ordovician through a series of charging positions during 3 accumulation periods - middle Caledonian, late Hercynian, and Himalayan. In total 11 hydrocarbon charging positions were identified at intersection zones of the northeast-trending faults and northwest-trending flower strike faults. There are anomalies in all parameters on hydrocarbon charging positions. With increasing distance from the charging positions, anomalies of oil density, wax content, dry gas coefficient, hydrogen sulphide content, gas/oil ratio, well production, 4-/1-MDBT ratio of crude oil weakened, and natural gas' carbon isotope composition becoming lighter along a northwest to southeast direction are present. Evidence from main hydrocarbon pathway systems theory, formation mechanisms of fault intersection zones, and obvious improvement in reservoir properties at intersection zones supports this viewpoint. Further exploration activities in the Ordovician of the Tazhong area should be conducted in the North Slope's west area, and intersection zones in tectonic up-dip direction should be emphasized. Copyright © 2016 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

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

Although a large amount of petroleum has been discovered in the Tarim Basin, the origin of the oils is still disputed. Yingmaili Oilfield was selected as a case study to further examine hydrocarbon generation and accumulation in the basin. Detailed geochemical studies were conducted to unravel the formation mechanisms. The oils in the field correlate well with Middle–Upper Ordovician (O 2+3 ) rocks (or similar rocks). Oil–oil and oil–source rock correlation by maturity parameters of saturate and aromatic hydrocarbons suggest that the Yingmaili and adjacent oils are primarily comparable to source rocks deeper than 6000 m. The results also showed that carbonates might be important potential source rocks as indicated by a relatively high abundance of aromatic sulfur compounds and relatively high C 29 /C 30 -hopane and C 35 /C 34 -hopane ratios of the oils, which are typical features of carbonate source rocks. We suggest the oil from wells YG2 and YG2-1C are more suitable to be end members from the O 2+3 source rocks (or similar rocks) than the oil from well YM2 as previously suggested. We also suggest that the previous model of hydrocarbon migration along the Ordovician unconformity should be revised. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Abstract: The superimposed basins in the Tarim Basin are characterized by multiple source-reservoir-caprock combinations, multiple stages of hydrocarbon generation and expulsion, and multi-cycle hydrocarbon accumulation. To develop and improve the reservoir forming theory of superimposed basins, this paper summarizes the progress in the study of superimposed basins and predicts its development direction. Four major progresses were made in the superimposed basin study: (1) widely-distributed of complex hydrocarbon reservoirs in superimposed basins were discovered; (2) the genesis models of complex hydrocarbon reservoirs were built; (3) the transformation mechanisms of complex hydrocarbon reservoirs were revealed; (4) the evaluation models for superimposed and transformed complex hydrocarbon reservoirs by tectonic events were proposed. Function elements jointly controlled the formation and distribution of hydrocarbon reservoirs, and the superimposition and overlapping of structures at later stage led to the adjustment, transformation and destruction of hydrocarbon reservoirs formed at early stage. The study direction of hydrocarbon accumulation in superimposed basins mainly includes three aspects: (1) the study on modes of controlling reservoir by multiple elements; (2) the study on composite hydrocarbon-accumulation mechanism; (3) the study on hydrocarbon reservoir adjustment and reconstruction mechanism and prediction models, which has more theoretical and practical significance for deep intervals in superimposed basins. [Copyright &y& Elsevier]

Abstract: A total of 108 drill stem test (DST) crude oil samples and 10 reservoir fluid inclusion samples were investigated geochemically to identify the characteristics and origin of the crude oil in the Tazhong Uplift, Tarim Basin, NW China. Results show that the majority of oils share typical biomarker characteristics from the Middle-Upper Ordovician (O2+3) source rock and related crude oil features. These features include a distinct “V” shape in the relative abundance of C27, C28 and C29 regular steranes, and low abundances of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. Only a few oils display typical biomarker features indicating a Cambrian–Lower Ordovician (ϵ-O1) genetic affinity, such as linear or “anti-L” shape C27, C28 and C29 regular sterane distributions, and relatively high concentrations of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. It appears that most of the oils studied were derived from the O2+3 intervals, as suggested by previous studies. However, the δ13C values of individual n-alkanes indicate that most of the crude oils in the Tazhong Uplift represent a mixture of two end member oils, an O1-ϵ derived oil, such as from well TD2 (or TZ62 (S)), and an O2+3 derived oil, such as from well YM2. The data suggest that most of the oils in the uplift have a mixed origin, and do not originated from the Middle-Upper Ordovician strata alone. This conclusion is supported by data on the molecular composition of petroleum inclusions. This new oil mixing model is critical for reconstructing the hydrocarbon formation and accumulation history for the region, and may have important implications for further petroleum exploration in the Tarim Basin. [Copyright &y& Elsevier]

The accumulation mechanism of hydrocarbons in the Yingmai 2 Oilfield of the Tabei Uplift in the Tarim Basin is not well understood. Here, the characteristics and formation of Paleozoic faults in the Yingmai 2 Oilfield are studied with new 3D seismic data and regional geologic data. Inclusion features and geochemical parameters are used to investigate the faults controlling the oil and gas compositions. The results indicate that three fault systems developed in the Yingmai 2 Oilfield: a NNW-trending strike-slip fault system that formed in the middle Caledonian, a NW-trending strike-slip fault system that formed in the Caledonian–late Hercynian and a NE-trending thrust fault system that formed in the late Hercynian–Indosinian, which was associated with volcanic activity. The two strike-slip fault systems were important early hydrocarbon migration pathways in the late Caledonian–early Hercynian, late Hercynian, and Himalayan accumulation periods. The NE-trending thrust faults were sealed by volcanics, and divided the originally uniform oilfield into two accumulation systems during the Himalayan. This finding is supported by the differences in the compositions of the oils and gases in the eastern (YM area) and the western (YG area) Yingmai 2 Oilfield. The oil density, iC 4 /nC 4 , Ph/nC 18 , and V/Ni ratios of the oils in the reservoirs in the YM area are lower than those in the YG area, whereas the TMNr, TeMNr, 4-1/DBT, Pr/Ph, C 29 -diasterane/C 29 -regular sterane ratios, H 2 S content, and the content of Himalayan hydrocarbon inclusions are higher. The hydrocarbon accumulation in the Yingmai 2 Oilfield is attributed to multiple episodes of hydrocarbon charging and suggests that the YM area has greater exploration potential than the YG area. [ABSTRACT FROM AUTHOR]

Natural gases in the Carboniferous Donghe Sandstone reservoir within the Block HD4 of the Hadexun Oilfield, Tarim Basin are characterized by abnormally low total hydrocarbon gas contents (<65%), low methane contents (<10%) and low dryness coefficients (<0.5), and a reversal of the normal trend of carbon isotope ratios, showing δ 13 C methane (C 1 ) > δ 13 C ethane (C 2 ) < δ 13 C propane (C 3 ) < δ 13 C butane (C 4 ). Specifically, methane is enriched in 13 C with the variations in δ 13 C 1 values between gases from Block HD4 and gases from its neighboring blocks reaching 10‰. This type of abnormal gas has never been reported previously in the Tarim Basin and such large variations in δ 13 C have rarely been observed in other basins globally. Based on a comprehensive analysis of gas geochemical data and the geological setting of the Carboniferous reservoirs in the Hadexun Oilfield, we reveal that the anomalies of the gas compositions and carbon isotope ratios in the Donghe Sandstone reservoir are caused by gas diffusion through the poorly-sealed caprock rather than by pathways such as gas mixing, microorganism degradation, different kerogen types or thermal maturity degrees of source rocks. The documentation of an in-reservoir gas diffusion during the post entrapment process as a major cause for gas geochemical anomalies may offer important insight into exploring natural gas resources in deeply buried sedimentary basins. [ABSTRACT FROM AUTHOR]

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 δ 34 S of DBTs and high δ 13 C 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 δ 13 C of n -alkanes and relatively high δ 34 S 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 δ 34 S 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 δ 34 S 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. [ABSTRACT FROM AUTHOR]

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

Abstract: Unusually high dibenzothiophene (DBT) concentrations are present in the oils from the Tazhong-4 Oilfield in the Tazhong Uplift, Tarim Basin. Positive-ion electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) was used in combination with conventional geochemical approaches to unravel the enrichment mechanisms. Significant amounts of S1 species with relatively low DBE values (0–8), i.e., sulfur ethers, mercaptans, thiophenes and benzothiophenes, were detected in three Lower Ordovician oils with high thermal maturity, which were suggested to be the products of thermochemical sulfate reduction (TSR) in the reservoir. The occurrence of TSR was also supported by the coexistence of thiadiamondoids and abundant H2S in the gases associated with the oils. Obviously low concentrations of the DBE=9 S1 species (mainly equivalent to C0–C35 DBTs) compared to its homologues were observed for the three oils which were probably altered by TSR, indicating that no positive relationship existed between TSR and DBTs in this study. The sulfur compounds in the Tazhong-4 oils are quite similar to those in the majority of Lower Ordovician oils characterized by high concentrations of DBTs and dominant DBE=9 S1 species with only small amounts of sulfur compounds with low thermal stability (DBE=0–8), suggesting only a small proportion of sulfur compounds were derived from TSR. It is thermal maturity rather than TSR that has caused the unusually high DBT concentrations in most of the Lower Ordovician oils. We suggest that the unusually high DBT oils in the Tazhong-4 Oilfield are caused by oil mixing from the later charged Lower Ordovician (or perhaps even deeper), with high DBT abundances from the earlier less mature oils, which was supported by our oil mixing experiments and previous relevant investigations as well as abundant authigenic pyrite of hydrothermal origin. We believe that TSR should have occurred in the Tazhong Uplift based on our FT-ICR MS results. However, normal sulfur compounds were detected in most oils and no increase of δ13C2H6–δ13C4H10 was observed for the gas hydrocarbons, suggesting only a slight alteration of the oils by TSR currently and/or recently. We suspect that the abnormal sulfur compounds in the Lower Ordovician oils might also be a result of deep oil mixing, which might imply a deeper petroliferous horizon, i.e., Cambrian, with a high petroleum potential. This study is important to further deep petroleum exploration in the area. [Copyright &y& Elsevier]