In the 1970s, China's energy supply was mainly coal and oil. Natural gas, an important source of energy, was still ignored by most people at that time. The prevailing "monism" theory of oil-derived gas then held that coal-producing areas wouldn't produce natural gas. However, Chinese scholars first put forward the concept of coal-derived gas in 1978. In the next 40 years, the coal-derived gas geological theory in China has gone through the whole process of introducing, absorbing, innovating, developing, forming system and guiding the rapid development of natural gas industry. Its contents include the index system of gas source identification, the accumulation mechanism and distribution law, and the evaluation and prediction technique of coal-derived gas, etc. The application of the theory has accurately predicted more than five large gas fields of over 100 million m³ magnitude, making the proportion of coal-derived gas in natural gas of China soar from 10% to 67%, and propelling the rapid growth of natural gas reserves and production in China. Apparently, the theory has important strategic significance to Chinese natural gas industry and has made fundamental contribution to the fast development of gas industry in China.

Comprehensive studies on seismic, core, well logging, mud logging, well testing and laboratory data show that the primary reservoirs in lower Es₁(the lower first sub-member of Shahejie Formation) of the Banqiao slope in the Qikou sag are sand reservoirs developed with hyperpycnal flow. Such sediments are generally located in a semi-deep to deep lacustrine environment. The lithologic composition is characterized by gray-black mudstone with medium-fine sandstone or their interbeds. In the sandstone segment, the sequence of sedimentary grains is a series of upwardly-coarsening units (inverse grain sequence) in pairs with a series of upwardly-thinning units (positive grain sequence); intralayer eroded surfaces are developed; and various types of fluviatile bedding structures can be found, such as cross-bed bedding, parallel bedding, climbing bedding and lenticular bedding. Hyperpycnal flow sediments involves eroded water channels, channel complexes, branch channels, proximal sand bars, distal sand bars and sheet lobes, of which the channel complexes have large monolayer thickness, coarse granularity, good sorting, low shale content and good reservoir properties. According to seismic attributes, sandstone thickness and core observations, the sedimentary distribution of the hyperpycnal flow has been analyzed in lower Es₁ of the Banqiao slope in the Qikou sag. Based on the result, the targeted pre-exploration plan has delivered good results; the single-well production test is high and stable. This proves the promising exploration of lithologic reservoirs in the middle and deep hyperpycnal flow in continental rifted basins.

The characteristics of Sinian-Cambrian source rocks were analyzed comprehensively by using drilling and outcrop data etc. The results show that the source rocks in Doushantuo Formation and Qiongzhusi Formation have mainly Type I organic matter, average TOC of 1.38% and 1.29%, and average R_o of 2.5% and 2.22% respectively, and are both in high-over mature stage. Based on the thermal evolution index of Well Chi7, the Baker-R_o model was determined to be suitable for R_o history simulation. Through experimental test and comparison study, the hydrocarbon generation rate curve and organic carbon restoration coefficient were corrected, and the gas migration & accumulation factor of the eastern Sichuan Basin was determined at 0.4%. Then, the basin simulation was carried out. It is found that:(1) the quantity of gas generated by the pre-salt source rocks in the eastern Sichuan Basin is 192.54×10¹²m³, and the gas resources are 7701×10⁸m³; and (2) the Datianchi-Shuangjiaba-Mingyuexia structural belt in the south of Kaijiang-Xuanhan paleo-uplift, and the Fangdoushan-Dachigan structural belt in the east of the eastern Sichuan Basin are on the direction of oil and gas migration, where the pre-salt Cambrian Longwangmiao Formation and Sinian Dengying Formation are favorable exploration strata.

Many wells in eastern Sichuan Basin delivered good oil and gas shows in the Jurassic formation, but they have not been given enough attention due to the fact that the Jurassic structural highs were almost eroded. Therefore, identifying the exploration potential is of great significance in guiding the exploration of the Jurassic reservoirs in the eastern Sichuan Basin. The conditions of source rocks, reservoirs, structures and preservation are analyzed, and the results show that the source rocks in the Lower Jurassic Lianggaoshan Formation and Da'anzhai Member are relatively thick, the effective source rock in the Lianggaoshan Formation is 5.6-35.8 m thick, and that in the Da'anzhai Member is 2.7-58.0 m thick; the TOC of the Lianggaoshan Formation is 0.15%-3.86%, and that of the Da'anzhai Member is 0.15%-2.76%, both about 1.00% on average; the high organic matter abundance indicates hydrocarbon generating is at a peak period there and the resources are rich; sandstone and limestone reservoirs are of extremely low porosity and permeability, but favorable reservoirs in beach bars and shelly beaches are distributed over a large area in the central and northern parts of the eastern Sichuan Basin; the interbedded source-reservoir assemblage is favorable for short-distance migration and accumulation of hydrocarbon; the well preserved Jurassic formation in the wide and gentle syncline of the fold belt provides good preservation conditions. All these points reflect that the Lower Jurassic Lianggaoshan Formation and Da'anzhai Member in the eastern Sichuan Basin have good exploration potentials, especially the Xuanhan-Kaijiang-Liangping-Wanzhou region has the best hydrocarbon accumulation conditions in the central and northern parts. Finally, about 5000 km² in the Lianggaoshan Formation and about 3000 km² in the Da'anzhai Member are proposed for favorable areas for future exploration.

The study on the shale reservoirs in the Lower Cambrian Shuijingtuo Formation in western Hunan-Hubei region are relatively less, and their heterogeneity severely limits the exploration of the shale gas. Taking the Shuijingtuo Formation shale as a target, and through analysis of thin sections, mineral content, organic geochemistry and SEM on profile and drilling data, the distribution and heterogeneity characteristics of the shale reservoirs in the Shuijingtuo Formation were studied. The result shows that the favorable facies for the development of the shale reservoirs is the deep water shelf, while dominated by carbonaceous shale and siliceous shale in the study area. The Shuijingtuo Formation is divided into two third-order sequences:the Sq1 is dominated by siliceous continental shelves, and the Sq2 is carbonaceous continental shelves more widely distributed. Macroscopically, siliceous and carbonaceous shales are developed in the transgressive system tract, which constitute an organic-rich shale zone; while calcareous and silty mud shales are developed in the highstand system tract. Microscopically, the shale reservoirs in the transgressive system tract have the features of increasing clay minerals and organic carbon content and decreasing brittle mineral content, and the reservoir space evolved from matrix pores to dissolved and organic pores, showing increasing total porosity; the shale reservoirs in the highstand system tract change in the opposite. The heterogeneous distribution of the shale reservoirs may be controlled by changes in sea level, source supply and biological effects, as well as diagenetic, tectonic and hydrogeological effects during the sedimentation.

According to the comparison and analysis of 3D seismic, drilling, well logging, thin section and inclusion data and skeletal sand body transport ridges, a study was carried out on the main controlling factors for the formation of the transport ridges on the unconformity in the buried hill in Penglai 9-A Oilfield. The result shows that the formation of the ridges is mainly related to the physical properties and lithology of the buried hills, the transport ridges and the structural ridges do not necessarily overlap, and the development of the fractures in the semi-weathered rocks is the key to the lateral transport system; the transport ridges are controlled by structural height difference and buoyancy, and they are superimposed with the structural ones; the sand ridges along the unconformity can be used as transfer stations of shallow hydrocarbon accumulations, and the effective combination of trap area on the sand ridge, faults and ridges controls the abundance of the shallow accumulations; if the trap area is larger, and the faults cut into the high of the trap, the abundance of the reservoir in shallow traps is high, and this has been confirmed by drilling data. In addition, it is found that the ridges are important to control hydrocarbon accumulation in the slope and bulge zones uncovered by source rocks.

The accumulation law of recoverable tight oil resources has been a hot point in present studies. The distribution of oil resources in tight oil basins is firstly investigated based on multiple global unconventional databases, especially in three basins with high tight oil production:the Williston Basin, Permian Basin, and Gulf Basin in North America, and then control factors on the accumulation of the recoverable tight oil resources are analyzed from the conditions of hydrocarbon sources, the characteristics of stratigraphic assemblages, and the development of local sweet spots, based on field production performances of thousands of typical tight oil wells, with the purposes for providing basic data for the exploration of tight oil outside North America. The study results indicate that, geographically, recoverable tight oil resources are mainly distributed in conventional oil and gas areas such as the Cordillera front belt in the Americas, the Western Siberia in Russia, and the Paleo-Tethys region in North Africa-the Middle East; and geologically, they are dominant in the Cretaceous, Upper Devonian, Middle-Lower Permian and Upper Silurian formations, and related to the primary source rocks developed all over the world. These recoverable tight oil resources show three accumulation laws:close to extensively distributed source rocks with high abundance and moderate maturity; in tight reservoirs dominated by inter-source and interbedded assemblages; and in sweet spot zones developed on the slope belt close to sedimentary centers and weak in tectonic activity.

Based on the outcrop data of the West Kunlun Mountains, drilling information on drilled through Cambrian wells and seismic profile characteristics in the Tarim Basin, the paleotectonic pattern at the end of Sinian has been studied to analyze the relationship with the distribution of source rocks of lower Cambrian Yuertusi Formation of the basin, thus to clarify the distribution characteristics of source rocks of the Yuertusi Formation in southwest depression of the Tarim Basin. The results suggest that there is the nearly east-westward ancient uplift at the end of Sinian in the Bachu-Tazhong area. There is a set of tidal flat sedimentary deposits on the top of uplift and the water here is relatively shallow, where has no deposition or phase change in the Yuertusi Formation, but has deposition in the Yuertusi Formation of the depression on north and south sides of the uplift. The Yuertusi Formation in the southwest depression of Tarim Basin is distributed in the depression formed by normal fault in Nanhua-Sinian rift or early Caledonian and extended mainly from the northeastern front-middle section of Kunlun Mountains to the Maigaiti slope region with a large scale of rift. Well Ross 2 in the middle depression of Ordovician Penglaiba Formation recently has made significant oil and gas discoveries, which indirectly confirmed the rich hydrocarbon source conditions of the deep Cambrian.

The Permian Lucaogou Formation in the Junggar Basin is one of the oldest continental shale systems with liquid hydrocarbons in China. It contains diamictite deposits in a paralic salty lake basin, with abundant tight oil and shale oil resources. The Jimsar sag is a typical example with rich liquid hydrocarbons in eastern Junggar Basin. The analysis of actual geologic data of shale systems shows that the Lucaogou shale system has two petroleum systems (upper and lower) characterized by continuous hydrocarbon accumulation in thick self-sourced reservoirs composed of thin interlayers. First, the Lucaogou Formation was deposited in a paralic lacustrine environment, where intermittent seawater invasion caused mass organism die-off, making it possible to accumulate and preserve abundant organic matters. This formation is chiefly composed of fine-grained diamictite deposits, and can be subdivided into 2.5 tertiary sedimentary cycles in 6 layers. Second, the source rocks, with major lithologies of carbonate mudstone and siliceous mudstone, concentrate in the second and fifth members of the Lucaogou Formation (P₂l₂ and P₂l₅). Their TOC contents are mostly higher than 4% and the kerogen is mainly of Type Ⅱ. Their R_o values range between 0.6% and 1.1%, which indicates that they are within oil generation window. Third, the reservoir rocks are generally tight and comprised of carbonate rocks, carbonate sandstone and siliceous sandstone, with the porosity mostly of 6%-12% and the air permeability less than 0.1mD. The pore space is mainly composed of intragranular pores and intergranular dissolved pores which are connected by pore throats with the diameter from dozens of nanometers to hundreds of nanometers. The oil saturation generally ranges between 80% and 90%, thus the oil storage condition is better. And fourth, the formation fluid pressure is normal or slightly abnormally high. The average crude density is 0.8971 g/cm³, and average viscosity at 50oC is 165.2 mPa·s; therefore, the crude oil is the product of low-medium thermal evolution. In stratigraphic conditions, the fluid flowability is poor. The Lucaogou Formation in the Jimsar sag has abundant tight oil and shale gas resources. According to the evaluation results, it has technically recoverable tight oil resources of 0.91×10⁸t, and P₂l₁ and P₂l₄ are the "sweet spot intervals" of tight oil, the sweet spot is mainly in the central sag. Moreover, it has technically recoverable shale oil resources of 1.10×10⁸t, and P₂l₂ and P₂l₅ are the "sweet spot intervals" of shale oil, the sweet spot is also chiefly in the central sag.

To get systematic research and deep understanding of the source rock in the Teng 2 block, Baiyinkundi sag, Erlian Basin, using cores, cuttings, and geochemical technology, the geochemical parameters of the source rocks were tested and analyzed, including the abundance, type and maturity of the organic matter. The research result shows that the source rock in the Teng 2 block are mainly distributed in the Shahai Formation and Jiufotang Formation; the cumulative thickness is above 700m; the organic matter abundance is generally in the medium-good level; the type of the organic matter is Ⅱ_a-Ⅱ_b; the thermal evolution has entered the oil generating window; the maturity of the organic matter in the lower source rock is higher than that in the upper source rock. Moreover, the oil generating potential of the Jiufotang Formation is much better than that of the Shahai Formation; the average original hydrocarbon generation potential is 13.26 mg/g; the average hydrocarbon expulsion potential is up to 7.68 mg/g; and the average oil-to-gas conversion coefficient gradually increases with the depth of burial.

Through observation of field outcrops, identification of thin section and physical property analysis, the characteristics and main controlling factors of microbial carbonate reservoir in the upper member of Lower Cambrian Xiaoerbulake Formation in Akesu area, Tarim Basin have been examined in detail. It is concluded through the study that two kinds of megascopic structures are developed, including microbial reef and microbial layer in this member; the former includes thrombolite reef and Epiphyton reef, and the later contains thrombolite, Epiphyton, stromatolite, laminite and spongiostromata biostromes. The microbial carbonate contains a variety of pores related to microbes and also non-microbial reservoir space. Thrombolite reef and spongiostromata biostrome are the most favorable microbial reservoirs, indicating different types of microbialite reservoirs differ widely in physical properties. The comparison of Yutixi profile with Sugetbulak profile shows that even the same type of microbialite reservoirs differ considerably. This is because the formation and preservation of microbial carbonate reservoirs are affected by the distribution of sedimentary facies, ancient landform features, diageneses and microbial structures.

Tight gas productivity prediction involves parameters such as reservoir properties and fracture shape. However, with low permeability, small pore size, strong reservoir heterogeneity, and wide distribution of pore throats, there are uncertainties in predicting reservoir and fracture parameters. Therefore, such productivity prediction is not comprehensive as only by giving one definite value to a parameter. The study shows that there are uncertainties in absolute reservoir permeability, effective permeability, and half lengths of effective induced fractures. In such case, an uncertain productivity prediction technology for tight gas was proposed. First, based on the open flow potentials of single wells, the productivity equation was used to inversely determine the probabilistic distribution of effective gas permeability and the half lengths of effective induced fractures, and the probabilistic distribution of the open flow potential of a block was calculated based on available reservoir and fluid properties; second, the probabilistic distribution of production profiles was predicted based on the parameter probabilistic distribution and an analytical model. This method is applicable for both block and single-well probabilistic productivity prediction, and provides a new way to reduce the uncertainties in tight gas productivity prediction.

Common methods of reservoir fracture identification and prediction include conventional well logging and FMI logging technologies, which are mainly applied to carbonate and sandstone reservoirs. However, less studies were carried out, and no effective method for fracture identification and prediction of sandy conglomerate reservoirs with ultra-low permeability. In this study, taking the sandy conglomerate reservoir with ultra-low permeability in Well Hong 153 in the Junggar Basin as an example, a quantitative characterization method has been established, which integrates geological, seismic and well logging techniques. First, the causes, development characteristics and main controlling factors of fractures are analyzed by cores, thin sections and other data to describe fractures at macroscope scale; second, fracture identification and interpretation models are built using core, FMI logging and conventional logging data, which are used for single-well fracture identification and prediction of sandy conglomerate reservoirs with ultra-low permeability; third, after extracting prestack seismic anisotropic attributes, fracture density and orientation are predicted based on seismic, well and sedimentary data; finally fracture identification and prediction results are verified by core, FMI logging, well and production test data. Application of the method to Well Hong 153 shows that the accuracy of fracture identification is 71.3%, and proves that the fracture prediction results from pre-stack seismic data are in good agreement with the actual production conditions.

It is difficult to accurately describe the thin reservoirs in unconformity traps with strong seismic reflections. Taking the Mesozoic unconformity trap in the Changdi area in the Jiyang depression as a case, the method for strong reflection separation is studied, the separation process is established, the selection of key parameters in the separation process is discussed, and the models are established to verify the feasibility of the separation method and select sensitive parameters for reservoir prediction. The study shows that the matching tracing algorithm with local frequency as a constraint can effectively avoid outliers, enhance the stability and increase the speed of calculation. Considering well logging data and near-well seismic data, it is proved that a 0.6 λ (scale factor) can find out strong reflections and highlight effective reservoir information in the target area. In the separated data volume, there is a positive correlation between the amplitude attribute and the effective reservoir thickness, which can reflect the lateral distribution characteristics of the reservoir. The drilling results of the wells are consistent with the predictions, which verifies the reliability of the method.