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Summary Numerous technical papers have been published on the reservoir evaluation of tight sand gas in recent decades. It is believed that tight sand gas is characterized by low permeability, complex pore structure, abnormal pressure, and low gas saturation. Researchers have characterized tight gas in terms of, for example, statistics; and some of them are increasingly interested in the effect of fluid pressure and pore structure on gas saturation. However, there is still a lack of effective experimental and mechanism analysis. The focus of this paper is to investigate the effect of two factors on controlling the tight gas saturation. A method was proposed for determining the in-situ injection pressure of the DB 2 gas reservoir in the Kuqa area during the gas-accumulation period, and the result was 1.2 MPa. A polyetheretherketone carbon-fiber core holder (maximum temperature 180 °C, maximum confining pressure 30 MPa) was designed for the microcomputed-tomography (CT) simulation experiment. After that, four physical simulation experiments of different fluid pressures (0.1, 0.5, 1.5, and 5.0 MPa) were implemented using X-ray CT and the new core holder to study the effect of fluid pressure and pore structure on gas saturation. The results show that the fluid pressure and micropore connectivity are important factors for gas-saturation increase; the number of gas clusters (connected pores containing gas) increases with the increase of fluid pressure and the maximum volume of gas clusters increases with the increase of pore connectivity. The connected pores with the largest volume are an important source of gas-saturation contribution. The three types of modes (the blowing balloon mode, stitching mode, and composite mode) of microscopic gas-cluster formation are discussed. The blowing balloon mode is key to gas-saturation growth in the period of low fluid pressure or the early stage of the injection process. The stitching mode is key to gas-saturation growth in the period of high fluid pressure or the late stage of the injection process. The above research system investigates the quantitative control of fluid parameters (pressure) and reservoir parameters (pore structure) on gas saturation, which might change the situation where previous research was too focused on the pore-structure and fluid-pressure characterization, with a lack of quantitative control analysis of reservoir gas saturation. It provides a valuable reference and framework for the reader to conduct further quantitative research on tight gas saturation.

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 reservoir diagenetic process and the petroleum charge histories of the Cretaceous Bashijiqike Formation (K1bs) in the Kuqa Depression, Tarim Basin were studied using an integrated petrographic, fluid inclusion, reservoir diagenesis and basin modeling approach. A suite of techniques were used in the investigation including optical microscopy, scanning electron microscope (SEM), X-ray diffraction (XRD), fluorescence spectroscopy, microthermometry, and Laser Raman microspectroscopy. The workflow comprises petrographic characterization of the reservoir sandstone, identification of fluid inclusion assemblages, and construction of the diagenetic history of the reservoir sandstone with reference to the hydrocarbon charge and emplacement. Key diagenetic events identified include quartz overgrowths, early calcite cementation, dolomite cementation, alteration of kaolinite, bitumen emplacement, micro-quartz and ankerite cementation. The first diagenetic event was characterized by quartz overgrowths and followed by calcite and dolomite cementation. Kaolinite and ankerite cementation were the last diagenetic events, coincided with hydrocarbon charge and emplacement. Three episodes of hydrocarbon charge and emplacement have been recorded by the diagenetic products and fluid inclusions in the K1bs Formations: (1) the first episode of oil charge was recorded in the early calcite cement, and were trapped around at 18 Ma; (2) the second and third episodes of hydrocarbon charge were recorded in the telo-diagenetic ankerite, and were trapped around at 4–6 Ma. The timing of oil emplacement determined from fluid inclusion homogenization temperature and basin modeling is consistent with the formation order of the diagenetic minerals. This study has thus demonstrated that integrated analysis of fluid inclusion and reservoir diagenesis can be an effective tool for determining hydrocarbon charge and emplacement history.

A series of fault-related folds developed in the Dabei Gas Field of the Kuqa Depression, western China form major traps for hydrocarbon accumulation. The Bashijiqike (K 1 bs) sandstone reservoirs in the different fault-related folds of the Dabei Gas Field display similar excess fluid pressure, formation water type and salinity, and as well as light oil and gas properties. The light oil and gas in the K 1 bs sandstone reservoir of the traps share the same source and were generated at a thermal maturity level of 1.4–1.6% R o and 1.7–2.3% R o , respectively. To investigate the fluid evolution in the fault-related fold traps, an integrated fluid inclusion analysis was performed including petrography, fluorescence spectroscopy, microthermometry, Laser Raman spectroscopy and thermodynamic modeling. The fluid evolution recorded by the fluid inclusions in the different fault-related folds indicates that the formation fluid was characterized by low salinity at normal hydrostatic pressure from approximately >9–5 Ma. From 5 to 3 Ma the formation water salinity and fluid pressure increased rapidly. The formation water attained the highest salinity at approximately 3 Ma to present while the pore fluid overpressure decreased with time in the reservoir. Two episodes of oil and one episode of gas charge were identified in the K 1 bs sandstone reservoir with the second episode of oil charge occurring around 5–4 Ma, while the gas charge occurred around 3–2 Ma. The injection of new fluids associated with oil and gas charge caused changes of the formation water salinity in the different fault-related fold traps within the gas field. The fluid evolution in the Dabei Gas Field can be used to indicate fault-related fluid flow as the thrust faults are suggested to be the primly pathways for fluid migration and the fluid flow was controlled by the reactivation of these thrust faults. The similarity of the oil and gas charge histories, formation water salinity and fluid pressure evolution in the K 1 bs sandstone reservoirs among the different fault-related traps in the Dabei Gas Field implies that the fault-related fluid flow process and activation of the thrust faults were concomitant since approximately 9 Ma.

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

The Kuqa Foreland Basin (KFB) immediately south of the South Tianshan Mountains is a major hydrocarbon producing basin in west China. The Kelasu Thrust Belt in the basin is the most favorable zone for hydrocarbon accumulations. Widespread overpressures are present in both the Cretaceous and Paleogene reservoirs with pressure coefficients up to 2.1. The tectonic compression process in KFB resulted from the South Tianshan Mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the Kelasu Thrust Belt. The overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with PVT and basin modeling. Overpressures at present day in the mudstone units in the Kelasu Thrust Belt and reservoir sandstones of the Dabei Gas Field and the Keshen zone are believed to have been generated by horizontal tectonic compression. Both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the Kela-2 Gas Field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data. The overpressure evolution for the Cretaceous reservoir sandstone in the Kelasu Thrust Belt evolved through four stages: a normal hydrostatic pressure (>12–5 Ma), a rapidly increasing overpressure (∼5–3 Ma), an overpressure release (∼3–1.64 Ma) and overpressure preservation (∼1.64–0 Ma). Overpressure developed in the second stage (∼5–3 Ma) was generated by disequilibrium compaction as tectonic compression due to the uplift of the Tianshan Mountains acted at the northern monocline of KFB from 5 Ma to 3 Ma, which provided abundant sediments for the KFB and caused the anomalously high sedimentation rate during the N2k deposition. From 3 Ma to 1.64 Ma, the action of tectonic compression extended from the northern monocline to the Kelasu Thrust Belt and returned to the northern monocline of KFB from 1.64 Ma to present day. Therefore, the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage (∼3–1.64 Ma) and overpressure caused by disequilibrium compaction from 5 Ma to 3 Ma was only preserved in the Kela-2 Gas Field until present day.

Under the joint action of gypsum-salt rocks and faults, fluid evolution process is complicated in the northern Tuzimazha, Kuqa Depression, Tarim Basin. In the past, however, the oil and gas distribution rules in this area were less studied, so the related understanding was insufficient. In this paper, the reservoirs in Well Block Tubei 1 were analyzed by means of fluid inclusion and quantitative grain fluorescence (QGF) techniques. Based on tectonic evolution history, burial history, thermal history and hydrocarbon generation history, the paleofluid evolution process in this area was reproduced. It is shown that the well block experienced hydrocarbon charge in two periods. The first period is the early–middle stage (16–9 Ma) of Miocene Kangcun Fm (N 1–2 k ), when it was charged with oil, with the corresponding characteristics of yellow and white–yellow fluid inclusion fluorescence and the QGF Index higher than 4, indicating that there were paleo-oil reservoirs at the early stage of the reservoirs. And at the late stage, the fluids that were accumulated at the early stage escaped because the gypsum-salt rocks were cut by faults, and bitumen remained in the reservoirs. It is also the evidence for the escaping of the early charged oil that the total scanning fluorescence (TSF) of the hydrocarbon adsorbed to the surface of the current reservoirs is generally unimodal. The second period is the late stage (about 3 Ma) of Pliocene Kuqa Fm (N 2 k ), when the natural gas and light oil charging occurred. Correspondingly, there are two inclusions, i.e. black gaseous hydrocarbon inclusion and blue fluorescence inclusion located along the edge of the quartz grains. At this stage, the gypsum-salt caprocks deepened and their sealing capacity was recovered due to a strong plastic flow. Moreover, the trap was uplifted violently under the effect of Himalaya orogeny, and a large amount of natural gas and a little light oil were accumulated.

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.

The accumulation of CBM depends on a favorable combination of the right properties of the coal that produces and reservoirs CBM, an adequate pressure and temperature regime and the right preservation conditions. Recent exploration has shown that there are widespread CBM accumulations in synclines world wide. The favorable trapping mechanisms for CBM in synclines were examined from a theoretical viewpoint and using laboratory experiments with some well documented examples from the coal fields in northern China, where CBM is currently under production. Apart from the presence of favorable structural, stratigraphic and the pressure-temperature pre-requisites, the CBM reservoir pooling mechanism in synclines appears to be primarily controlled by the ubiquitous presence of a down-dip water flow fed from continuous meteoric water recharge from topographic highs near the basin margins, which is able to maintain the reservoir pressure and form an effective hydrodynamic seal. The synclinal CBM reservoirs are usually characterized by a high abundance of CBM at the axis of the syncline, which decreases gradually up-dip towards the weathering zones. The presence of thick overburden strata above the target coal seams near the axis of synclines is also favorable for the CMB accumulation and preservation. This model has been applied for CBM exploration and production in the Qinshui Basin, Shanxi Province, northern China and has achieved good outcomes.

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

Hetianhe gasfield in Bachu region of the Tarim Basin is mainly composed of three reservoir-caprock assembly, namely regional caprock of upper mudstone, middle mudstone and lower mudstone of the Carboniferous and reservoir of Bachu bioclastic limestone, glutenite and the Ordovician carbonate buried hill. Natural gas in Hetianhe gasfield sourced from the Cambrian source rock. It is thought that gases in Ma4 well block in the east of Hetianhe gasfield are mainly crude-oil cracked gases, while those in Ma3 and Ma8 well blocks in the west are the mixture gases of kerogen cracked gases and crude-oil cracked gases. Natural gas is rich in H2S and accumulated in multiply stages as the result of TSR. The accumulation history is divided into three stages, namely accumulation and breakage in the late Caledonian-early Hercynian, migration and dissipation in the late Hercynian and accumulation in Himalayan. The main accumulation of reformed gas reservoir is in Himalayan.

The Ordovician buried hill reservoir in the western Lunnan area, a type of dissolved fracture and cavernous reservoir, is mainly composed of heavy oil. The oil is the mixture sourcing from the Middle-Lower Cambrian and Middle-Lower Ordovician, with three stages of pool forming process: (1) the destruction and parallel migration/accumulation during the late Caledonian to early Hercynian; (2) the oil and gas accumulation during the late Hercynian characterized by adjustment upward along faults and parallel migration/accumulation; (3) the formation of heavy oil during the latest Hercynian. The Ordovician buried hill reservoir is affected by the diffusion of light oil and gas but had no hydrocarbon charging during the late Yanshan period to Himalayan period, but in this period, formed the association of heavy oil and dissolved gas cracked from crude oil with dry coefficient of 0.91–0.96. The study on accumulation process of the Ordovician buried hill reservoir has important implications for the exploration potential of early oil and gas accumulation in the cratonic area of the Tarim Basin.

Bitumen from the Nanpanjiang Basin occurs mainly in the Middle Devonian and Upper Permian reef limestone paleo-oil reservoirs and reserves primarily in holes and fractures and secondarily in minor matrix pores and bio-cavities. N2 is the main component of the natural gas and is often associated with pyrobitumen in paleo-oil reservoirs. The present study shows that the bitumen in paleo-oil reservoirs was sourced from the Middle Devonian argillaceous source rock and belongs to pyrobitumen by crude oil cracking under high temperature and pressure. But the natural gas with high content of N2 is neither an oil-cracked gas nor a coal-formed gas generated from the Upper Permian Longtan Formation source rock, instead it is a kerogen-cracked gas generated at the late stage from the Middle Devonian argillaceous source rock. The crude oil in paleo-oil reservoirs completely cracked into pyrobitumen and methane gas by the agency of hugely thick Triassic deposits. After that, the abnormal high pressure of methane gas reservoirs was completely destroyed due to the erosion of 2000–4500-m-thick Triassic strata. But the kerogen-cracked gas with normal pressure was preserved under the relatively sealed condition and became the main body of the gas shows.

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 No. 15 coal seam of the Pennsylvanian Taiyuan Formation and the No. 3 coal seam of the Permian Shanxi Formation in the Southeast Qinshui Basin are relatively thick (> 3 m), laterally continuous, and are of anthracite rank (Ro = 2.2–4.5%). The depth of these coal seams is generally between 200 and 700 m. A tectonic-thermal event during the Jurassic to Cretaceous Yanshanian Orogeny controlled coalification and thermogenic hydrocarbon generation. Because the generation of late-stage bacterial gas, coalbed methane in the Southeast Qinshui Basin occupies two zones, which are the mixed thermogenic and late-stage bacterial gas zone near the basin margins, and the dominantly thermogenic gas zone in the structurally deep part of the basin. Basin hydrodynamics causes low gas content in the shallow subsurface ( 20 m3/t). Because cleats are rare and are mostly filled with calcite, the permeability of the coalbed methane reservoir is controlled by shear fractures. The recharge and flow of groundwater not only control gas content, but also control reservoir pressure. Abnormally high pressure reservoir in the deep stagnant zone is a favorable area for coalbed methane exploration and development. The current coalbed methane wells are generally completed in the deep stagnant zone.

Coal Bed Methane(CBM) occurs in coal seams in the states of adsorption gas, free gas and water-dissolved gas. Its dissipating starts with desorption, and then it dissipates outwards in the states of free gas and water-dissolved gas. The dissipating approach is classified to three patterns: Free gas in pores dissipates through the cover rocks; hydrocarbon molecules in the cap-rocks and reservoir diffuse because of concentration gradient; gas dissolving in water is directly taken away by water. According to the controlling factors of CBM conservation and considering the cover rocks, soleplate, hydrological region identification and dissipating theory, three geological models of CBM dissipating are built: closed system model, lateral hydrological closed model and open system model.

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.

The evolution of coalbed gas reservoir is characterized by coalbed gas geochemistry and gas content. On the basis of burial history and thermal history, the forming process of coalbed gas reservoir and the gas accumulative history in the Qinshui Basin are discussed in this paper. The difference of the thermal history, geochemistry characteristic, and gas accumulative history between Yangcheng and Huozhou areas shows that the formation of coalbed gas reservoir in the Qinshui Basin is controlled by the geological process in the critical stage and the critical moment. The components and isotopes of coalbed methane are determined by the stage at which the coal maturation reaches its maximum rank. The coalbed methane accumulative history is related to the temperature and pressure of the coal burial history, because the coalbed gas is mainly in adsorptive state. It is stated that the gas content in the coal seam is controlled by the moment when the coal seam is uplifted to the shallowest position.

The current accumulation and enrichment of CBM reservoir is a result of the preservation and destruction of former CBM, after the superposing evolution of reversingand-uplifting and the subsequent evolution within the coalbearing basin. The critical moment of the CBM reservoir formation is the time when the burying depth of the overlying net thickness amounts to the least in geological history after the gas generation of coal beds. Except the coal-bearing basins of lower metamorphism, most basins suffered the evolution stage of reversion and uplift. The formation of the CBM reservoir is controlled by the beginning and lasting time, and the intensity of reversing and uplifting. The tectonic evolution after reversing and uplifting also affects the accumulation of CBM in coal-bearing basin. The CBM constantly dissipates in the area of chronically uplifting and denudating. The area developed overlying sedimentation is advantageous to the preservation of CBM, but also can lead to the reduction of CBM saturation.

Kuqa depression is a foreland basin developed with Mesozoic-Triassic-Jurassic coal-bearing formation. The research results of the coal-derived hydrocarbon foreland basins in Kuqa depression indicated that the coal-bearing formation can be the rich sources for generating gas because of their thickness and rich source rocks with gas-generating predominant kerogen. Although the foreland thrust belt mainly acting in compression is very complicated, integral large structural traps can be formed. Moreover, the thrust belt can act as the passage for communication with deep source rocks. The high quality gypsolish and gypseous mudstone cap rock developed in the upper formation is the key for the formation of the large gas field. The late formation of reservoirs in the large gas fields depended on the hydrocarbon-generating history controlled by the foreland basin and the developing process of foreland thrust belt.

Kuqa depression bears not only plenty of natural gas, but also a large amount of condensate and small quantity of crude oil. Based on the geochemical correlation between the Jurassic and Triassic terrestrial hydrocarbon source rock, this paper confirms that the natural gas in Kuqa depression belongs to coal-type gas and the main gas source rock is attributed to the middle to lower Jurassic coal series formation, while the main oil source rock is the upper Triassic lacustrine mudstone. The authors indicated that Kuqa depression was slowly subsided in Mesozoic, but rapidly went down in Late Tertiary, which made the Jurassic and Triassic source rock suddenly deep-buried and rapidly evolved to high and over-mature phase since 5 Ma. The Triassic source rock is postponed to the Early Miocene during 23−12 Ma when entering the oil-generating peak, while the Jurassic is suspended to the latest 5 Ma, especially since 2.5 Ma to the dry gas-generating period, which is one of the characteristics of the source rock thermal evolution in Kuqa depression. This paper presents a two-stage trapping and late gas trapping model in Kuqa depression whose characteristics are: The main oil and gas reservoirs have different sources. The oil reservoir is formed early while the gas reservoir is formed lately. During the early stage, it, mainly as oil, takes long distance lateral migration, while in the later stage, it, mainly as gas, takes the vertical migration and also has lateral migration. The trap formed in different time on the south and north sides of the depression and evolved into a distributional pattern with oil in the south part and gas in the north, also oil on the outer ring and gas on the inner ring. This paper points out that the late trapping of the natural gas in Kuqa depression is favorable for the preservation of large gas fields.

The mother matter of Ordovician source are mainly sapropelic and generate oil in mature stage, since the high plants did not appear in Ordovician period, which is well known by internal and external scholars. Now we find a kind of Orodovician source rock generating mainly light oil and gas in mature stage during appraising source rocks in the Tarim Basin. The organic matters of this source rock are chiefly constructed by benthic brown algae in organisms (showing as macro algae), and are similar to humic source in hydrocarbon generation. The natural gas generated by this kind of source matters is obviously different from the sapropelic gas.

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.

On the basis of a large amount of natural gas components and the carbon isotope as well as some other analysis data in Kela 2 gas field, the geochemical characteristics, source, origin, and formation process of natural gas have been discussed. The components of gas in the field tend to be “dry”, and the drying coefficient is close to 1.0. The carbon isotope tends to be heavier, for instance, the average of δ13C1 is −27.36‰ and that of δ13C2 is −18.5‰ Comprehensive analysis shows that humic natural gas in the Kuqa petroleum system comes mainly from Triassic and Jurassic source rocks, and the contribution of Jurassic source rocks to the pool maybe is more than that of Triassic rocks. The main cause that the gas tends to be dry and bears heavier isotope composition lies in the fact that Kela 2 natural gas is the accumulation of late production of humic source rocks, and it is affected by the abnormal high pressure as well. Considering the hydrocarbon generating and structural history, we can regard the gas pool formation processes as twice filling and twice adjusting (destroying), that is, the filling and destroying process in the early Himalayan movement and the filling and adjusting in the late Himalayan movement.