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Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The Muli permafrost area is the only midlatitude permafrost area where natural gas hydrates (NGHs) have been drilled. Although a series of achievements has been made in studies on NGH accumulation conditions in the permafrost area, related studies on gas hydrate stability zones, gas sources and groundwater are still controversial and need further work. Based on geophysical, geological and geochemical data, this paper systematically elaborates the main NGH accumulation conditions in the Muli area in terms of the pressure‒temperature stability conditions, fault structure, gas composition, gas source, reservoir characteristics, groundwater distribution and topographic characteristics. The results show that the thicknesses of the NGH stability zone range from 491.0 to 962.7 m. The fault structure can provide a pathway for hydrocarbon gas migration from deep to NGH stability zones, in which thrust faults can prevent the upwards migration of gas by sealing it below the hanging wall block. Rock fractures in the NGH stability zone can not only be gas migration channels, but also serve as a reservoir space for NGH accumulation. The hydrocarbon gas of NGHs shows multiple origins and is mainly composed of oil-associated gas. The formation of frost mounds related to the overpressured gas ejection caused by NGH decomposition may imply the existence of NGHs. Synthetically, similarities and differences in NGH accumulation conditions between the Muli permafrost area and other high-latitude permafrost areas are proposed, and the 'regression' NGH accumulation pattern in the Muli area is constructed. The study results can enrich theoretical knowledge of terrestrial NGH accumulation, and provide scientific guidance for NGH exploration in midlatitude permafrost areas. [ABSTRACT FROM AUTHOR]

Tight sandstone reservoirs are widely developed in the Mesozoic Yanchang Formation of the Ordos Basin, China. There is a lack of understanding on the sedimentary setting, source-reservoir relationship and oil accumulation conditions in this area. In this study, through the comprehensive analysis of the distribution of tight oil, we evaluated the properties and petrological features of reservoir, geochemical characteristics of source rocks, the source-reservoir relationship, as well as the trapping, preservation and accumulation conditions of tight oil in the Chang 7 Member, and predicted the sweet spots of tight oil in the study area. The results show that the Chang 7 Member is a typical low-porosity and ultra-low permeability reservoir with great tightness, small pore throat and high capillary pressure, and must have been of near-source accumulation. The source rocks are mainly developed in the Chang 73 submember, and the reservoirs mainly occur in the Chang 71 and Chang 72 submembers, forming a combination mode of “lower source rock and upper reservoir”. Sandbodies with good connectivity and fractures being well developed in local areas are the main hydrocarbon transport systems. The abnormal high pressure caused by hydrocarbon generation and pressurization is the main driving force of tight oil accumulation. The mode of hydrocarbon transportation is dominated by the vertical or lateral migration from underlying source rocks or adjacent source rocks to reservoirs within a short distance. Following the integrated evaluation of lithology, physical properties and oil saturation of reservoirs and geochemical characteristics of source rocks, we grouped the sweet spots of Chang 7 Member into three types: Type I, Type II and Type III. Among others, the Type I sweet spots are the best in terms of porosity, permeability and source rock thickness and hydrocarbon enrichment which should be the focus of oilfield development. This study lays an important foundation for the economic and efficient development of tight oil in the Chang 7 Member of Heshui area, and has important implications on tight sandstone reservoirs in other regions of Ordos Basin in China.

A breakthrough has been made in the Permian Maokou Formation by the well of YB 7 in Yuanba area of the Sichuan Basin, which shows a great exploration potential. With continuous enrichment of data, it is necessary to strengthen the understanding of oil and gas laws and to summarize the main controlling factors of hydrocarbon accumulation, by which a basis for oil and gas exploration and deployment may be provided. In this paper, basic accumulation conditions and characteristics of gas pools in the Maokou Formation were studied, gas-source correlation and hydrocarbon charging time analyses were carried out, and some main controlling factors for hydrocarbon accumulation were summarized. The study area has favorable conditions for source rock and hydrocarbon preservation. The reservoir is mainly shoal superimposed karst fractured type. The gas pool is characterized by abnormally high pressure and high temperature. The natural gas is accumulated from both kerogen and crude oil cracking gas, mainly derived from the Wujiaping Formation. The oil and gas are largely filled in the Middle Jurassic, characterized by continuous filling. The hydrocarbon accumulation in the study area is mainly controlled by reservoir development, source rock conditions and hydrocarbon preservation conditions.

To determine the accumulation conditions and pattern of tight oil in oil shales in the Damintun Sag, Bohai Bay Basin, this study investigated the basic geological conditions of the source rocks and reservoirs in the sag using methods such as organic carbon analysis, whole-rock XRD analysis, and field emission scanning electron microscopy. The results show that: (1) The high-quality source rocks in the lower submember of the fourth member of the Shahejie Formation (E2S42) in the Damintun Sag have high organic matter abundance, favorable organic matter types, high hydrocarbon expulsion efficiency, and high fluidity. Therefore, they provide sufficient oil sources for tight oil accumulation.; (2) During the burial of organic-rich shales, the thermal degradation of organic matter produces large amounts of organic acids, which can dissolve carbonate minerals. In this way, secondary pores are formed.; (3) The special microscopic pore structure that connects fractures to pores is the key to the enrichment of tight oil is a key factor for the high oil saturation of pores in oil shales; (4) The breakthrough pressure (up to 100 MPa) and specific surface area of dolomitic mudstones in the E2S42 submember are significantly higher than those in other horizons. As a result, the dolomitic mudstones can effectively seal the underlying tight reservoirs; (5) Compared with the tight oil in tight sandstones, the tight oil in the oil shales in the study area has significantly superior geological conditions for reservoir formation, such as the favorable arrangement of hydrocarbon expulsion channels, low filling resistance, and the presence of reservoir spaces. [ABSTRACT FROM AUTHOR]

As a special type of reservoir, tuff tight reservoir has attracted much attention. However, previous studies on the tuff tight reservoir formed in the burial diagenetic stage are few. The accumulation characteristics of the Carboniferous Haerjiawu Formation tuff tight oil formed by burial dissolution were studied to determine the main controlling factors and to establish the model of reservoir formation. The results show that the source rocks of the Haerjiawu Formation are of high organic matter abundance, good organic matter types, and are in the stage of mature evolution. Oil-source correlation shows that the crude oil of the tuff reservoirs formed by burial dissolution is mainly from source rocks in the Haerjiawu Formation. The dissolution pores are formed by dissolution of a large amount of organic acids produced from the upper source rocks. The formation of tuff reservoir caused by burial dissolution is controlled by the distribution of Haerjiawu Formation source rocks, the physical properties of the tuff reservoir formed by burial dissolution and the trap condition. The hydrocarbon accumulation model of “the mature source rocks in the lower part supply hydrocarbons, the organic acids in the upper part dissolve to form tuff reservoirs with good physical properties and effective traps storage hydrocarbons” is formed under favorable configuration of several accumulation conditions. The research results could be considered a reference regarding the distribution and prediction of tuff tight oil formed by burial dissolution in similar situations in other parts of the world. [ABSTRACT FROM AUTHOR]

With the successful development of unconventional hydrocarbons, the production of unconventional hydrocarbons has increased rapidly. However, a single conventional or unconventional model is not suitable for the mechanism of hydrocarbon accumulation in a given basin or sag. Based on data from drilling, logging, and geophysical analysis, the hydrocarbon accumulation mechanism in the Hari sag in the Yingen-Ejinaqi basin, China, was analyzed. There are three sets of source rocks in the Hari sag: the K1y source rocks were evaluated as having excellent source rock potential with low thermal maturity and kerogen Type I-II1; the K1b2 source rocks were evaluated as having good source rock potential with mature to highly mature stages and kerogen Type II1-II2; and the K1b1 source rocks were evaluated as having moderate source rock potential with mature to highly mature stages and kerogen Type II1-II2. Reservoir types were found to be conventional sand reservoirs, unconventional carbonate-shale reservoirs, and volcanic rock reservoirs. There were two sets of fault-lithologic traps in the Hari sag, which conform to the intra-source continuous hydrocarbon accumulation model and the approaching-source discontinuous hydrocarbon accumulation model. The conclusions of this research provide guidance for exploring multi-type reservoirs and multi-type hydrocarbon accumulation models. [ABSTRACT FROM AUTHOR]

The foreland slope in the south marginal Junggar Basin (SMJB) is geologically favorable for mass lithologic oil and gas reservoir accumulation. Based on outcrops, thin sections, individual-well facies, and cross-well stratigraphic correlation, the stratigraphic distribution and features of the Upper Jurassic Kalazha Formation were investigated in the SMJB. There are two sedimentary sources in the southwest and southeast Kalazha Formation, which thin out from south to north and vanish in the northern slope. Fan deltas occur in the southwest, and braided river deltas occur in the southeast. Kalazha reservoir rocks and sedimentary facies were predicted using joint 2D and 3D seismic impedance inversion. According to the overall analysis, the Kalazha Formation in the foreland slope is favorable for hydrocarbon accumulation, considering structural highs as the destination of long-term hydrocarbon migration and the updip wedge-out zone in the north with potential lithologic traps. The accumulation model was established with source rocks, reservoir rocks, caprocks, and migration systems for the lithologic hydrocarbon reservoirs in the Kalazha Formation in the SMJB. As per the model and regional stratigraphic and structural features, Kalazha lithologic hydrocarbon reservoirs mainly formed in the annular updip wedge-out zone in the foreland slope. Our deliverables may provide useful information for mass lithologic hydrocarbon accumulation in the foreland slope and deep to ultra-deep hydrocarbon exploration in the SMJB.

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Well Gaotan 1 was tested a high yield oil and gas flow of more than 1 000 m3 a day in the Cretaceous Qingshuihe Formation, marking a major breakthrough in the lower assemblage of the southern margin of Junggar Basin. The lower assemblage in the southern margin of the Junggar Basin has favorable geological conditions for forming large Petroleum fields, including: (1) Multiple sets of source rocks, of which the Jurassic and Permian are the main source rocks, with a large source kitchen. (2) Multiple sets of effective reservoirs, namely Cretaceous Qingshuihe Formation, Jurassic Toutunhe Formation and the Khalza Formation etc. (3) Regional thick mudstone caprock of Cretaceous Tugulu Group, generally with abnormally high pressure and good sealing ability. (4) Giant structural traps and litho-stratigraphic traps are developed. The northern slope also has the conditions for large-scale litho-stratigraphic traps. (5) Static elements such as source rocks, reservoirs and caprocks are well matched, and the dynamic evolution is suitable for large oil and gas accumulation. The lower assemblage of the southern margin of the Junggar Basin has three favorable exploration directions, the Sikeshu Sag in the west part, the large structures in the middle and eastern part, and the northern slope. [ABSTRACT FROM AUTHOR]

With the further exploration of the Jurassic strata in the Turpan-Hami Basin, the targets for hydrocarbon exploration have been gradually shifted from the tectonic belts around sags to the proximal lithological zones of deep sags. Based on the systematic coring of the first exploration well (well Qintan-1) in the center Shengbei sub-sag, this study conducted experiments of organic carbon, pyrolysis, gas chromatography (GC), nuclear magnetic resonance (NMR), and low-temperature nitrogen adsorption. Then, this study systematically analyzed the geological conditions and major controlling factors for the accumulation of tight sandstone gas in the deep part of the Shengbei sub-sag. The results show that: (1) Multiple sets of coal-measure source rocks have developed in the Jurassic strata in the center Shengbei sub-sag, providing plenty of gas sources for multilayered hydrocarbon accumulation; (2) Tight sandstones have poor physical properties and complex pore structures. However, high-permeability zones and anomalous zones of nano-scale pores have developed in the deep part, providing favorable spaces for the accumulation and preservation of tight oil and gas in the deep part; (3) Compaction and late carbonate cementation are key factors in reservoir densification. The microscopic storage space and connectivity of the tight sandstone reservoirs in the Shengbei sub-sag were improved due to the dissolution of fluids in coal measure strata. The occurrence of high-quality reservoirs in the Shengbei sub-sag is significantly controlled by source rocks, and both the former and the latter are characterized by adjacent sources and reservoirs and short-distance migration and accumulation. Furthermore, the special geological phenomena of chert cementation, abnormally high homogenization temperatures of fluid inclusions, and abnormal pyrolysis parameters confirm the presence of low-temperature hydrothermal activity in the deep part of the target strata. Therefore, the center Shengbei sub-sag has geological conditions for the large-scale accumulation of primary gas and, thus, is a key area for future hydrocarbon exploration. • The microscopic pore structures of tight reservoirs are determined through a large number of tests and experiments on unconventional oil and gas. • It is confirmed for the first time that the deep part of the study area still hosts effective tight gas reservoirs. • The geological conditions for hydrocarbon accumulation in the deep part of the study area are systematically analyzed. • A comprehensive map showing the geological factors in the hydrocarbon accumulation in the depression center of the study area is established. [ABSTRACT FROM AUTHOR]

The Carboniferous-Permian strata in Henan Province are a set of coal-bearing series of transitional marine-continental facies，of which the mudstones have potentials for shale gas exploration.The mudstones are characterized by a variable thickness of the individual effective mudstone layer and a huge accumulative thickness.In this paper，we utilized the outcrop and borehole core data and investigated the accumulation conditions and the reservoir characteristics of the shale gas in the Carboniferous and Permian coal-bearing strata of Henan Province.The total organic carbon(TOC)，organic matter types，thermal evolution degree，contents of brittle minerals and clay minerals，and pore morphological types of the mudstones were determined by the TOC analyzer，microscopic identification of kerogen，reflectance measurement of vitrinite，X-ray diffraction(XRD)，low temperature nitrogen gas adsorption，respectively.The results showed that the abundance of organic matters of the mudstones was relatively high，with the TOC contents in the mudstones of the Taiyuan，Shanxi and Xiashihezi Formations being 0.95% ～8.04%，0.78% ～9.41%and 0.2% ～ 2.13%，respectively.The types of organic matter were dominated by typeⅢ，followed by typeⅡ2.The thermal evolution degree ranged from mature to over-mature stage which was favorable for the formation of dry gas.The maturity of the mudstones had a zoned distribution，with the highest maturity being distributed along the Jiaozuo-Zhoukou belt and the lower maturity being distributed towards the south and north from this belt.The XRD analysis showed that the clay minerals of the mudstones could account for 62.0%while the brittle minerals only accounted for 34.1%，indicating that the mudstones had a higher gas adsorption capacity but were difficult for hydraulic fracturing.The clay minerals were mainly composed of 57.1%of illite/smectite mixed layer and 23.5%of kaolinite，which were beneficial to the formation of pore space.The porosity of the mudstones ranged from 1.0%to 4.5%，and the permeability varied between 0.003 and 0.032 mD.The experiment of low temperature nitrogen gas adsorption revealed that the morphological types of the pores included the parallel plate-slit pores and the inclined plate-slit pores.The meso-pores provided the vast majority of specific surface area and total pore volume.The gas contents could reach 1.0 ～3.0 m3/t which is suitable for the condition of shale gas reservoir.It was concluded that the siliciclastic member in the middle Taiyuan Formation(H1)and the basal part of the Shanxi Formation(H2)have a higher hydrocarbon potential.The major favorable exploration areas are those having a good preservation condition or a less serious influence from the regional thermal events.

The formation conditions of shale gas in Wufeng-Longmaxi Formation of Yanjin-Gongxian area were analyzed on the basis of field observation and experimental data,and then the main factors for shale gas accumulation were discussed. Results show that black shale at the bottom of Wufeng-Longmaxi Formation is a deep-water shelf deposit product. The dessert shale gas from the first stage of Wufeng to the fourth stage of Longmaxi was complete. The organic carbon content is between 2.7%-6.0%. Mainly for the high organic carbon content,the thickness of black shale rich in organic matter is 30-50 m. In the high gas horizon,nanometer organic pores and pyrite intracrystalline pores are abundant,and the average rate of porosity is 2.28%-3.48%,providing a good reservoir space for the adsorbed gas and free gas. Structural strength in the research area is weak and large faults are less. There are good conditions of roof and floor. The pressure coefficient is more than 1,which reflects the suitable preservation condition. The main factors for shale gas accumulation are as follows:deep shelf sedimentary environment,high organic carbon content,abundant nanometer pores,high level porosity,and high pressure coefficient.

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

For the practice of petroleum exploration, the traditional petroleum geological theory has made great contributions to the development of petroleum industry. But, with the development of petroleum exploration into unconventional petroleum, the traditional petroleum geological theory and insight have come across with many problems and challenges, which can not direct unconventional hydrocarbon exploration effectively. In the perspective of condition of unconventional hydrocarbon accumulation, “source” is not only the rock generating hydrocarbon, but also reservoir and target; tight rock can be effective reservoir; enclosed mechanism of unconventional hydrocarbon is different from the conventional hydrocarbon; continuous and quasi-continuous hydrocarbon accumulation is not controlled by traditional trap condition; detention and short distance migration can form hydrocarbon reservoir; the evaluation methods of storage conditions are not exactly the same as conventional hydrocarbon. In the perspective of hydrocarbon accumulation mechanism, hydrocarbon reservoir can be formed under the mechanism of non-buoyancy in continuous large area; in the perspective of state hydrocarbon occurrence, besides free state, hydrocarbon can be accumulated in the states of adsorption and dissolution; in the perspective of distribution model of hydrocarbon enrichment, except for trap and high point, hydrocarbon can be accumulated in basin sub-sag and slope, sag-wide oil-bearing. The unconventional hydrocarbon resource around the world is more than 4 times of conventional hydrocarbon resource, indicating tremendous exploration prospect. [ABSTRACT FROM AUTHOR]

Combined with the shale distribution and geological characteristics of marine-terrigenous facies coal measures in the Yangtze area，taking the Permian Longtan Formation in South Sichuan Basin as example，the authors investigated the accumulation conditions and the reservoir characteristics of marine-terrigenous facies coal measures shale gas using many experimental methods，such as organic carbon，Rock-eval pyrolysis，maceral identification，X-ray diffraction (XRD)，scanning electron microscope (SEM)，high pressure mercury injection，low temperature gas sorption，etc. The results show that the marine-terrigenous facies coal measures shale has the features of rapid vertical-lateral variation，huge cumulative thickness (mainly over 100 m)，small individual thickness (generally <40 m)，and commonly accompanied with coal bed，limestone and tight sand．The marine-terrigenous facies coal measures shale from Longtan Formation in South Sichuan Basin，which featured with high organic matter abundance (TOC=0.85%-35.70%，average 6.73%)，mainly with humic type organic matter （kerogen δ13C=-28.0‰--23.5‰），high-over thermal evolution level (Ro=1.95%-2.4%，average 2.22%)，rich in clay minerals content（20.3%-92.3%，average 61.9%），and relatively low brittle minerals content (6.3%-65.7%，average 27.7%). The shale reservoir fracturing from Longtan Formation is worse than that of marine shale. The porosity of the Longtan Formation shale in South Sichuan Basin is mainly over 3%. Many types of pores were developed，including intergranular pore (29.08%)，dissolution pore (30.18%)，organic pores (16.74%)，intragranular (10.56%)，inter-crystalline (4.94%) and microfracture (8.5%)，which provide reservoir space for the accumulation of shale gas. Gas generation capability from the Longtan Formation shale is relatively better，and its main gas content can be 1.0-3.0 m3/t. [ABSTRACT FROM AUTHOR]

Based on the data from drilling, core samples, etc., taking the Lower Cambrian Qiongzhusi Formation and the Lower Silurian Longmaxi Formation shales as study target area, authors investigated the accumulation conditions of marine shale gas from the Lower Paleozoic in the south region of Sichuan Basin. The results indicate that the Qiongzhusi Formation and the Longmaxi Formation black shales in this region are mainly formed in shelf sedimentary facies. The study region features great organic-rich shale thickness, high organic abundance (average TOC >2%), Type I and II organic matter, high-over thermal evolution level, rich in brittle mineral, abundant in micro- and nanometer pores, and high gas content, which are in favor of the generation and enrichment of shale gas. Compared with the shales in North America, in which the shale gas has been explored and developed successfully, it is suggested that the Lower Paleozoic in the south region of Sichuan Basin has good accumulation conditions for shale gas. Therefore, the Qiongzhusi and Longmaxi Formations are considered as the practical targets for shale gas exploration, and their favourable areas of shale gas enrichment are also purposed. [ABSTRACT FROM AUTHOR]

Abstract: Through lithological analysis of reservoirs, fluid inclusion test and simulation experiment, combined with geochemical, seismic, well logging and formation testing data, this paper studies the favorable geological conditions for tight gas accumulation in the Upper Paleozoic of the Ordos Basin, specifies the characteristics of tight gas reservoirs, and summarizes the key techniques for tight gas exploration and development. The gas source conditions of large area hydrocarbon generation and continuous hydrocarbon injection, widespread delta facies sandstone reservoirs, and the accumulation mode of short-distance migration facilitate the formation of the large-scale tight gas reservoirs in the Upper Paleozoic of the Ordos Basin. The Upper Paleozoic tight gas reservoirs in the Ordos Basin cover a large area and have many gas-bearing formations and multiple pressure systems. The tight reservoirs, which were formed before gas accumulation, are of high heterogeneity. Full digital seismic prediction technique for thin reservoirs, fine logging evaluation technique for tight gas reservoirs, and integrated supporting techniques for gas development provide technical support for further exploration and development. [Copyright &y& Elsevier]

Marine carbonate oil and gas fields have become an important exploration area in China and even across the world. Their formation, distribution and enrichment are special owing to the complexity of the deposition, diagenesis and accumulation, which is caused by the multiplicity of the carbonate depositional environments and facies, huge extensions of formation time and burial depth, complication of diagenetic evolution, heterogeneity as well as the development of pores, caves and fractures affected by various factors. Oil and gas accumulations in carbonate rocks are not strictly controlled by the second-order structure belt. Most of them, under certain structural settings, are controlled by sedimentary diagenesis and its favorable facies. The hydrocarbon reservoir type is predominantly stratigraphic. Based on the worldwide researches of carbonate fields, the paper concludes that 7 main factors control the formation and distribution of middle-large marine carbonate stratigraphic fields. [ABSTRACT FROM AUTHOR]

In recent years, a series of progress and breakthroughs havebeen made in the conventional and unconventional natural gas exploration in the Turpan-Hami Basin, and the geological conditions and resource potentials havebeen updated constantly. At present, it is in urgent need to assess the natural gas resources in the Turpan-Hami Basin comprehensively, so as to figure out the natural gas resources and provide a basis for promoting the exploration and deve opment of natural gas in this basin.The natural gas is mainly distributed in J1b-J2x1+2, J2x3+4, J2s-J2q, J3k, K1s and Esh strata in Turpan Hami Basin.We have comprehensively studied the reservoir geological conditions as hydrocarbon generation, petrophysical property, res-ervoir-caprock assemblage?reservoir formation and reservoir accumulation model. Using the mathematical statistics, it was considered that the source rocks are mainly from Jurassic Xishanyao and Badaowan formations, the area where the large amount of hydrocarbon generation intensity is located in the main subsidence area of Taipei Sag, thus possessing the material conditions of forming large-scalegas fields. The grit sandstone of braided river delta distributary channel is the main stratum, the sand bodies vary quicklyalong the lateral and have poor connectivity, low porosity and permeability. Conventional gas accumulation model is mainly controlled by structure and lithology, four types of accumulation models are classified according to controlling factors, i.e., forward differentiation, reverse differentiation, vertical differentiation and mixed oil and accumulation model.Unconventional tight Sawa Kesunghide is mainly controlled by sedimentation and diagenesis. They have good osmosis desserts in some localareas in lowporosity and low permeability reservoirs of large area. Using analogy method,statisticalmethod and the Delphi method, we have calculated out the conventional gas resources and the residual resources, about 2 434.57×108m3 and 1 412.56× 108m3, fe-spectively. Then, using resource abundance analogy method. volumetric method and rapid evaluation method, we alsocalculated out thetight sandstone gas resources in Shuixigou group of the Turpan Hami-Basin. Its resources and recoverable resources are about 5 087.66 × 108m3 and 1 940.6 × 108m3 , respectively.The favorable exploration direction and targets of natural gas were pointed out by contrasting the residual resource, the abundance of residual resources. [ABSTRACT FROM AUTHOR]