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Two sets of thick salt have developed in the Kuqa foreland basin, which has a great influence on the evolution of subsalt reservoirs. The abnormal favorable reservoirs, developed at a depth of approximately 4000–5500 ms, was several hundred meters from the bottom of the salt body based on the drilling data. The study was carried out to understand the formation of the favorable subsalt reservoirs based on the techniques of formation water salinity analysis, scanning electron microscopy (SEM) and cast thin section analysis. The results showed that during the first stage, the high-salinity formation water began to infiltrate and crystallized in the pores after the salt deposition, causing the decrease in the porosity. During the second stage, the formation water salinity decreased for the groundwater activities, which caused dissolution of the salt in the pores, a favorable subsalt reservoir was formed. During the third stage, hydrocarbons were charged and accumulated in the favorable subsalt reservoir. The high heat conductivity characteristic of the salt cooled the subsalt reservoir, which was also helpful for the forming of the favorable reservoir.

Due to the high expense of deep oil and gas exploration, prediction of gas-bearing properties before drilling is crucial for deep gas reservoir of tight sandstone. Deep tight sandstone gas fields in Kuqa Foreland Basin are characterized by high abundance, high gas saturation, high pressure, high and stable yield, which belong to high-efficiency tight gas reservoir. Based on theoretical analysis of controlling factors and mechanisms of gas-bearing properties for tight sandstone gas reservoir, and taking tight sandstone gas fields with high effectiveness such as Dibei, Keshen and Dibei gas fields in Kuqa Foreland Basin as examples, formation condition and mechanism of high-efficiency tight sandstone gas reservoir in Kuqa area are studied through a comparative analysis of typical tight sandstone gas reservoir in Sichuan Basin and Ordos Basin. The results show that the formation condition of deep gas reservoir of tight sandstone in Kuqa foreland basin includes four factors: i.e., overpressure gas charging, fracture development, “early-oil and late-gas” accumulation process and favorable preservation condition. The overpressure gas charging and fracture development are the most important factors for formation of high-efficiency tight gas reservoirs in Kuqa Foreland Basin. High-quality source rocks, high source-reservoir pressure difference, and overpressure filling induced thereby are preconditions for formation of tight sandstone with high gas saturation. The fracture development controls gas migration, accumulation, and high yield of tight sandstone gas reservoir. The reservoir wettability changed by the early oil charging is beneficial to late natural gas charging, and the preservation condition of high-quality gypsum cap rocks is the key factor for gas reservoirs to maintain overpressure and high gas saturation. Matching of above four favorable factors leads to the tight sandstone gas reservoir with high abundance, high gas saturation and high gas production in Kuqa Foreland Basin, which is very different from other basins. Under the condition of little difference in physical property of tight sandstone reservoir, excessive source-reservoir pressure difference, facture development, preservation condition and current formation overpressure are the most significant factors to be considered in exploration and evaluation of deep tight sandstone gas. Keywords: Deep gas reservoir, Tight sandstone, Overpressure, Fracture, “Early-oil and late-gas” accumulation process, Preservation condition, Kuqa foreland basin

The Kelasu Thrust Belt is a favorable hydrocarbon accumulation zone in the Kuqa Sub-basin with several known giant gas fields including the Dabei and Kela-2 gas fields as well as the Dawanqi oil field. The origin and accumulation process of the hydrocarbons were investigated through an integrated petroleum geochemistry and fluid inclusion analysis, and basin modeling. Geochemical parameters indicate that the light oils from the Dawanqi oil field and Dabei gas field were generated from different sources as compared with light oils from the Kela-2 gas field. Light oils from the Dawanqi oil field and Dabei gas field are primarily derived from the terrestrial mudstones in the Jurassic Qiakemake (J2q) Formation with a maturity level of 1.4–1.6 %Ro, whereas light oils from the Kela-2 gas field are mainly derived from the terrestrial mudstones in the Triassic Huangshanjie (T3h) with a maturity level of 1.6–1.8 %Ro. Gases in the Kelasu Thrust Belt are dominated by coal-type gas and are primarily generated from the Jurassic coal measures. Carbon isotope ratios suggest that gases in the Dawanqi oil field and Dabei gas field were generated at a thermal maturity level of 1.6–2.3 %Ro, while gas in the Kela-2 gas field was generated at a thermal maturity level of 2.1–2.5 %Ro. Two episodes of oil and one episode of gas charge were delineated in the Dabei gas field. The second episode of oil charge occurred around 5–4 Ma, while gas charge occurred around 3–2 Ma. Three episodes of oil and one episode of gas charge were identified in the Kela-2 gas field. The latter two episodes of oil charge occurred around 5.5–4.5 Ma and the gas charge occurred around 3–2 Ma. The timing of the petroleum charge was also confirmed by the correlation between the maturity of the source rocks during the times of charge and the maturity levels of the light oil and gas in the reservoirs. The later oil and gas charge occurred at the same period in both the Dabei and Kela-2 gas fields, possibly relating to structural reactivation caused by regional tectonic compression, because intense tectonic compression and rapid uplift of the Tianshan Mountains occurred during the same period, which may have caused thrust fault activation and opening. Hydrocarbon expulsion from the source rocks during the period was possibly also related to the regional tectonic movement, providing hydrocarbon sources for the reservoirs.

The Dabei Gas Field is a recently discovered giant tight-gas field in the Kuqa Subbasin, western China. The reservoir porosity and permeability mainly range from 1% to 8% and from 0.01 to 1 md, respectively. The hydrocarbon (both gas and light oil) accumulation processes in the tight-sandstone reservoirs were studied based on detailed reservoir characterization, thermal maturity of both gas and light oil, hydrocarbon charge history, regional tectonic compression, and thrusting. Two episodes of oil and one episode of natural-gas charge were delineated in the tight-sandstone reservoir, as evidenced by (1) similar sources but different maturities for the gas and light oil, (2) the presence of abundant bitumen in the tight-sandstone reservoir, (3) the presence of both hydrocarbon gas inclusions and oil inclusions with two distinct fluorescence colors, and (4) the presence of two groups of aqueous inclusions (coeval with the petroleum inclusions) with contrasting homogenization temperatures and salinities. The oil inclusions with the blue-white fluorescence color were determined to have been trapped at 5–4 Ma, whereas the gas charge may have occurred at circa 3–2 Ma, corresponding to a salinity change recorded in the aqueous inclusions. The hydrocarbon accumulation processes appeared to be controlled by the tectonic compression of the South Tianshan Mountains. Intense tectonic compression caused thrust fault reactivation, which provided pathways for hydrocarbon migration. Overpressure evolution of the reservoir indicates that an intense tectonic compression began at circa 5 Ma, which caused thrust activation and concomitant oil charge into the relatively porous part of the reservoir. Subsequent tectonic compression caused uplift and erosion associated with thrusting at the end of the Kuqa Formation deposition (ca. 3 Ma), with thrust faults and fractures acting as major migration pathways for the gas accumulation in the already-tight sandstone reservoir resulting from both compaction and tectonic compression.

There develop two sets of thick salt in the Kuqa foreland basin, the impact of salt thickness on geothermal temperature and thermal evolution of source rock was analyzed using transient thermal modeling method based on the two dimensional seismic profile from west to east of the basin and the related boundary condition. The results indicate that: (1) the change of salt plies will not have different impact on geothermal temperature when the total thickness of the salt body is constant; (2) the geothermal temperature of formations above the salt will increase about 0.3–0.6 °C/100 m, while the subsalt geothermal temperature will decrease about 0.6–1.0 °C/100 m in the west of the basin; the geothermal temperature of formations above the salt will increase about 1.9–2.3 °C/100 m, while the subsalt geothermal temperature will decrease about 0.2–2.6 °C/100 m in the east of the basin; (3) the value of vitrinite reflectance will be lagged about 0.02%/100 m averagely in the west of the basin, and will be lagged about 0.05%/100 m in the east. As the thermal conductivity of salt is negatively correlated with temperature, the salt body in the east has a shallower burial and lower geothermal temperature, so its overall thermal conductivity is higher, causing the changing rates of geothermal temperature and Ro are higher than the west. A case study of Dina 2 condensate field of Kuqa foreland basin indicates that the charge time of hydrocarbon there lagged about 7.5–9.0 Ma because of the delayed source rock thermal evolution caused by the salt, matching well with the formation period of trap, which is favorable for the late accumulation of hydrocarbon in this area. Key words: salt, conductivity, geothermal temperature, source rock, thermal evolution, basin modeling, Kuqa foreland basin, Tarim Basin

Kela-2 is a giant gas field with a proven reserve of 597 tcf in the Kuqa depression, northern Tarim Basin. Widespread overpressures have been encountered in the Eocene and Cretaceous sandstone reservoirs of the field, with pressure coefficients up to 2.1 from drill-stem tests and well-log data analysis. Disequilibrium compaction associated with horizontal tectonic compression may be the dominant overpressure mechanism in the sandstone reservoirs, because the overpressured sandstone with a maximum burial depth over 6000 m (19,685 ft) displays anomalously high porosity and low density. The causes for sandstone reservoirs with anomalously high porosity in the Kela-2 gas field were studied based on an integrated investigation of sandstone reservoir characteristics, paleo oil–water contact, petroleum charge history, and overpressure evolution. Collective evidence indicates that early oil charge had retarded the porosity reduction of the reservoir sandstone and resulted in disequilibrium compaction from overburden rocks, and overpressure from disequilibrium compaction and horizontal tectonic compression at the beginning of the rapid subsidence and deposition in the Kela-2 gas field again contributed to the preservation of the reservoir porosity: (1) overpressured mudstones in the Kela-2 gas field are characteristic of normal compaction, and overpressure was generated by horizontal tectonic compression instead of disequilibrium compaction; (2) the reservoir sandstones with high porosity and permeability are associated with high paleo oil saturation, as indicated by quantitative grain fluorescence (QGF) responses and anomalous QGF on extract intensity; (3) sandstone units below the paleo oil–water contact have very low porosity and permeability; and (4) three episodes of oil and one episode of gas charge are identified in the sandstone reservoirs of the Kela-2 gas field, and the later two episodes of oil charge occurred circa 5.5–4.5 Ma, which corresponds to the beginning of the rapid tectonic subsidence and deposition in the Kuqa depression. The initially charged oil in the sandstone reservoirs was subsequently displaced by gas at circa 3–2 Ma through fault activation at the edge of the anticline trap. The overpressure evolution for the K1bs reservoir sandstone in the Kela-2 gas field indicates that the apparent overpressure development in the sandstone reservoir began at 5 Ma following the major oil charge and has been maintained to the present. Overpressure development from 5 Ma in the sandstone reservoirs of the Kela-2 gas field is believed to be the dominant cause of the porosity preservation.

By analyzing the relationship between throat threshold and fluid forces of oil charge in tight reservoirs and according to the oil-charging mechanical conditions, the lower limits of throat at the interface between source and reservoir rocks and in the middle of reservoirs were determined theoretically. On the basis of Young-Laplace formula and the equilibrium between driving forces and capillary resistance, the threshold models were set up by using the maximum driving forces near the source-and-reservoir interface and inside reservoirs respectively. They were applied to the Yanchang Formation in the Ordos Basin, the middle-lower Jurassic in the Sichuan Basin and the Bakken Formation in the Williston Basin in America. The corresponding results near the interface are 15.74 nm, 29.06 nm, and 14.22 nm, and the ones in the middle of reservoirs are 39.45 nm, 37.20 nm, and 52.32 nm respectively. Accordingly, the threshold permeabilities of the three typical tight oil reservoirs calculated are 0.002 1×10−3 μm2, 0.006 1×10−3 μm2, 0.001 8×10−3 μm2 near the interface and 0.010 0×10−3 μm2, 0.009 4×10−3 μm2, 0.016 9×10−3 μm2 at the inner reservoirs. The rocks near the interface are complex, so there is a poor correlation between porosity and permeability, while inside reservoirs, homogeneous lithology results in good correlation between porosity and permeability. The porosity thresholds were determined as 2.16%, 2.00% and 3.50% respectively. Key words: tight oil, oil-charging throat threshold, fluid forces, driving forces, theoretical discussion, case study

The multi-stage hydrocarbon charge process of Kela-2 gas field in the Kuqa foreland basin was studied from the perspective of palaeo-fluid evidence by the analyses of fluid inclusions, fluorescence spectroscopy, FE-SEM (field emission scanning electron microscopy) observation, core micro-CT scanning, and hydrocarbon geochemistry. The result shows that the Kela-2 gas field has experienced three periods of hydrocarbon charge process: (1) charged with oil at the early-middle period of the Miocence (N1), (2) charged with high maturity oil & gas at the sedimentary period of the Pliocence Kuqa Formation (N2) and then destroyed by intense tectonic compression, and (3) charged with high- and over-maturity coal-derived gas since the Quaternary. The widely distributed residual dry bitumen, the occurrence of gas-liquid two-phase hydrocarbon inclusions, the residual oils observed in the nanopores, the higher QGF and QGF-E index, and the higher S1, S2 values of rock pyrolysis detected in both current gas zone and water zone, are the evidence of early oil charges. The residual dry bitumen, the occurrence of gas-oil-solid (bitumen) three-phase hydrocarbon inclusions, the loss of light n-alkanes and the relatively high content of aromatic hydrocarbons in the condense oil, and the abnormally high content of diamondoid hydrocarbons, are the strong evidence of gas flushing and deasphalting. Key words: palaeo-fluid, fluid inclusions, charge history, gas flushing, Kela-2 gas field

Coalbed methane (CBM) is an important type of unconventional gas. Commercial development of CBM in America has been very successful since the 1980s. The CBM industry in Australia and Canada has developed rapidly during the last decade. Commercial development of CBM in China started in the 1990s, and has made great progress. The geological theory of CBM in China has achieved great advancement in genesis, occurrence and accumulation. On the aspect of CBM genesis, five CBM genetic types (primary biogenic gas, secondary biogenic gas, thermal degradation gas, pyrolysis gas and mixed gas) are identified by studying the geochemical characteristics of CBM, and a tracing indicator system is established. The discovery of secondary biogenic gas in medium-high rank coal reservoirs has widened the potential of CBM resources. On the aspect of CBM occurrence, the gas adsorption regulation under combined action of temperature and pressure is revealed by conducting adsorption experiments of different coal ranks under varying temperature and pressure conditions. Besides, by applying the adsorption potential theory in CBM research, the adsorption model under combined action of temperature and pressure is established. The new model can predict CBM resources accurately, and overcome the limitation of the traditional Langmuir model which uses just a single factor to describe the adsorption characteristics of deep buried coal. On the aspect of CBM accumulation, it is proposed that there are three evolutionary stages during CBM accumulation, including gas generation and adsorption, unsaturated gas adsorption, gas desorption-diffusion and preservation. Controlled by tectonic evolution, hydrodynamics and sealing conditions, CBM tends to be regionally enriched in synclines. Advances in geological theory of CBM in China can not only improve understanding of natural gas, but also provide new ideas for further exploration of CBM.

Dominant factors controlling hydrocarbon distribution are analyzed from three aspects: the types, structural units and structural belts of the foreland basins of central and western China. There are four types of foreland basins recognized in China, superimposed, reformed, presenile, and newly-generated foreland basins. Hydrocarbon distribution is different in the four types of basins and is controlled by their respective hydrocarbon accumulation conditions, characteristics and patterns. Thrust belts, foredeeps, slope belts, uplift belts, and other structural units are developed in foreland basins. The different controls of these structural units on source rock development and evolution, trap type, hydrocarbon accumulation process, and preservation condition, cause different characteristics of hydrocarbon distribution in different structural belts. The main hydrocarbon enriched structural units are foreland thrust belts, in which the structural styles, tectonic evolution and the preservation of regional cap-rock are the critical factors for hydrocarbon accumulation. The configuration of faults and cap rocks in thrust belts determines the features and enrichment regularity of hydrocarbon and indicates hydrocarbon enriched locations and favorable exploration targets in various structural belts. Key words: foreland basin, structural unit, thrust belt, hydrocarbon distribution, controlling factors

Neotectonic movement refers to the tectonic movement that has happened since the Cenozoic, which is the latest movement. It has the most important influence on the basins in west China, especially on the hydrocarbon accumulation in the western foreland basins. We determined the time of neotectonic movement in the Kuqa Foreland Basin, which began from the Neogene, and analyzed the patterns of movement, which were continuous and fast subsidence in the vertical direction and intense lateral compression. The structure styles are that the faulting is weakened and the folding is strengthened gradually from north to south. We studied the control of neotectonic movement on the hydrocarbon accumulation process and model in the Kuqa Foreland Basin with basin simulation technique. The largest subsidence rate of the Kuqa Foreland Basin reached 1,200 m/Ma during the neotectonic movement, leading to rapid maturing of source rock within 5 Ma and a large quantity of hydrocarbon being generated and expelled. The thick neotectonic strata can form high quality reservoirs with the proved gas and oil reserves accounting for 5% and 27% of the total reserves, respectively. 86% of the structural traps were formed in the neotectonic movement period. The faults formed during the neotectonic movement serve as important migration pathways and they exist in the region where the hydrocarbon reservoirs are distributed. Abnormally high pressure caused by the intense lateral compression, thick neotectonic strata deposition and rapid hydrocarbon generation provide driving force for hydrocarbon migration. The accumulation elements match each other well over a short period, leading to many large gas fields formed later in the Kuqa Foreland Basin.

Considering its vertical distribution characteristics, this article argues that the Lower Palaeozoic source rock in the Manjieer Sag is composed of three sets of source rocks of Middle-Lower Cambrian, Middle-Lower Ordovician, and Upper Ordovician. The source rock of the Middle-Lower Ordovician Heituwa Formation has similar sedimentary facies and developmental features to the Middle-Lower Cambrian source rock, and has abundant organic material. The Upper Ordovician source rock is poor and limited in distribution. The source rocks have different thermal evolution histories. In central and western Manjiaer sag, Middle-Lower Cambrian source rock entered oil generation peak in Late Caledonian and Early Hercynian, Middle-Lower Ordovician source rock in Late Hercynian, and Upper Ordovician source rock in Late Yanshan and Himalayan. The threefold division of the source rock is the foundation of detailed study on the derived source and the accumulation process of marine oil in Tarim platform area. Key words: Lower Palaeozoic, source rock, thermal evolution history, Manjiaer Sag, Tarim Basin

Six petroleum source beds have been developed in the Kuche Depression (also known as “Kuqa Depression”) of the Tarim Basin, including three lacustrine source rocks (Middle and Upper Triassic Kelamayi and Huangshanjie formations, and Middle Jurassic Qiakemake Formation) and three coal measures (Upper Triassic Taliqike Formation, Lower Jurassic Yangxia Formation, and Middle Jurassic Kezilenuer Formation). While type I–II organic matter occurs in the Middle Jurassic Qiakemake Formation (J2q), other source beds contain dominantly type III organic matter. Gas generation rates and stable carbon isotopic kinetics of methane generation from representative source rocks collected in the Kuche Depression were measured and calculated using an on-line dry and open pyrolysis system. Combined with hydrocarbon generation history modelling, the formation and evolution processes of the Jurassic–Triassic highly efficient gas kitchens were established. High sedimentation rate in the Neogene and the fast deposition of the Kuche Formation within the Pliocene (5 Ma) in particular have led to the rapid increase in Mesozoic source rock maturity, resulting in significant dry gas generation. The extremely high gas generation rates from source kitchens have apparently expedited the formation of highly efficient gas accumulations in the Kuche Depression. Because different Mesozoic source rocks occur in different structural belts, the presence of both lacustrine and coaly gas kitchens during the Cenozoic time can be identified in the Kuche Depression. As shown by the chemical and stable carbon isotope compositions of the discovered gases, the formation of the giant gas pools in the Kela 2, Dina 2, Yaha and Wucan 1 have involved very different geological processes due to the difference in their gas source kitchens.

The coalbed methane resource is very abundant in Qinshui basin (3.28 1012 m3; 114 tcf). The investigation on the upper Paleozoic coalbed methane system is a guide to the exploration and development of coalbed methane. The upper Paleozoic coalbed methane system in the Qinshui basin is sealed by a low-permeability roof and floor strata comprising mudstone, siltstone, and bauxite of the Carboniferous Benxi Formation and the Permian Shanxi and Xiashihezi formations. The overburden is the Lower Permian Xiashihezi Formation and the Upper Permian, Triassic, and Middle Jurassic clastic deposits. The source and reservoir rocks are the Carboniferous–Permian coal seams. The hydrocarbon generation of the source rocks reached its first peak in the Late Triassic. The highest maturity was about Ro = 1.2% under a normal paleogeothermal gradient (2–3C/100 m; 1.1–1.7F/100 ft). A tectonic thermal event during the Jurassic and Cretaceous Yanshanian orogeny enhanced the coal maturity and caused a second peak of hydrocarbon generation. Varying igneous intrusions caused the coal maturity to be higher in the southern, northern, and eastern parts of the Qinshui basin instead of the central and western parts. The highest maturity was greater than Ro = 4% in the Jincheng area. The migrated thermogenetic coalbed methane accumulated in the reservoirs in which abnormally high reservoir pressure exists locally under the hydrodynamic drive. Because of the different hydrodynamic background and sealing condition, the distribution of coalbed methane content is inhomogeneous. The reservoir is undersaturated with gas in most areas. Based on the coalbed methane system investigation, we assessed the coalbed methane producibility in different parts of the Qinshui basin, and the major producibility area is in the southern part of the basin.

Hydrocarbon compositions and their carbon isotopic data for 94 natural gas samples were combined with the results of thermal simulation experiments to complete a comprehensive study of maturity, genetic types and sources of Lower Paleozoic marine hydrocarbon gases from the eastern Tarim Basin. All of the Lower Paleozoic gases are relatively dry (dryness coefficient >0.9) and belong to the marine sapropelic type of cracked gases. These gases are characterized by low δ 13 C 1 and low Δ (δ 13 C 2 −δ 13 C 1 ) values due to a lack of terrestrial source input. Thermal simulation experiments on Upper Proterozoic to Lower Paleozoic source rocks resulted in a δ 13 C 1 –R o regression equation that was used to discriminate the maturities and sources of the natural gases. These natural gases are divided into four genetic types: (1) humic, coal-derived pyrolytic gas; (2) lacustrine sapropelic oil-cracking gas; (3) the marine sapropelic, highly mature oil-cracking gas; and (4) overmature oil-cracking gas. Types (1) and (2) were mainly generated from the Upper Triassic-Middle and Lower Jurassic; types (3) and (4) are mainly generated from the Lower Paleozoic. The data can be used to describe multiple sources and multiple generating stages of natural gas.