Production capacity prediction of CBM is a difficult technical problem that the natural gas industry tries to solve. In order to explore the permeability mechanism and productivity rule of fractured CBM reservoirs in the "three soft" coking mining area under the condition of hydraulic fracturing， firstly， the influence of geometric characteristics of primary fractures on fracture growth rule was considered， and an improved hydraulic fracture growth model was established in combination with the classical PKN model； secondly， a reservoir dynamic permeability model was established based on the dynamic equation of reservoir pressure gradient， considering the influence of the geometric size change of hydraulic fractures on the porosity of primary fractures in coal during drainage and production； finally， based on the principle of fluid mass conservation， the productivity prediction model of CBM vertical wells in fractured reservoirs was established. This model was used to calculate the production capacity of Well GW-008 during the trial period of 70 days in the mining area， and it was compared with the actual discharge and production value. It was founded that the dynamic change curve of the theoretical calculation value and the actual discharge and production value was in good agreement with each other. The average daily gas output is 360.768 m3/d and 381.489 m3/d respectively， and the relative error is only 6%， thus verifying the correctness of the production capacity model. The research results are of great significance to the development and utilization of coalbed methane in the “three soft” areas of China.
There are more tight gas sandstone reservoirs in China. However， tight gas reservoirs are characterized by strong heterogeneous， low well productivity and it’s difficult to develop efficiently. Tight gas reservoir model zone in Ordos Basin with He 8 and Shan 1 multi-layer is studied as an example for enhancing well productivity， improving reserves producing degree and exploring efficient development model. Multi-layer horizontal wells development technologies are proposed. Firstly， feature of every layer is characterized finely and sweet point evaluation is done by 3D geologic and seismic model； Secondly， He 8 and Shan 1 layers are nominated and laid out in model zone for horizontal well development by formation optimized. Thirdly， length of gas-bearing sand to horizontal section ratio increased efficiently via geo-seismic steering. Length of gas-bearing sand to horizontal section ratio is 10% higher compared to adjacent field. The average AOF of horizontal wells is 0.873 million cube meters per day based on these technologies. Efficient development of tight gas reservoir is achieved.
The multi-stage acid fracturing， fracturing， and other layered stimulation often induced vertical non-uniform composite boundaries near commingled vertical production wells. To explore the influence of vertical non-uniformity of the stimulation boundaries on the flow in reservoir and pressure response of production well， the bottom-hole pressure response model of vertical commingled wells considering vertical non-uniform composite radii （VNCR） was established. Through the Laplace transformation， Bessel function， Cramer's Rule， and Stehfest inversion method， the bottom-hole pressure solution was obtained， the pressure response type curve was drawn and the flow regime was divided， and the influence of the VNCR distribution on the bottom-hole pressure response and flow regimes was analyzed. The results show that： Firstly， VNCR will cause new transitional flow and radial flow in the reservoir， resulting in pressure response characteristics of three-zone radial composite reservoir， and the new radial flow is determined by the proportion of VNCR thickness in the reservoir thickness. Secondly， there are multiple solutions to the impact of VNCR distribution on reservoir pressure response. Thirdly， the true VNCR distribution type cannot be obtained only by the bottom-hole pressure and pressure derivative curve， but the minimum， equivalent value， thickness ratio， equivalent volume of VNCR can be captured. It is concluded that the equivalent volume and equivalent boundary value of VNCR rather than the true distribution of VNCR can be captured by the bottom-hole pressure response. The reservoir model should be selected with extreme caution for interpretation when three-zone radial composite reservoir characteristics appear in the pressure response.
Hydraulic fracturing technology is one of the core technologies of shale gas development. Large-scale hydraulic fracturing technology may bring a large amount of flowback water （including both flowback water and produced water）， and flowback water has the risk of polluting groundwater and surface water. In this paper， the geochemical characteristics of flowback water from Weiyuan shale gas development area and formation water from different strata in Sichuan Basin are analyzed. The results show， flowback water in Weiyuan is characterized by high TDS and high content of heavy metal. However， compared to formation water， the contents of Na （7 334 mg/L， n=63）， Ca （297 mg/L， n=62）， Sr （73.07 mg/L， n=64）， Mg （32.1 mg/L， n=42）， Ba （153.12 mg/L， n=64）， Mn （1.83 mg/L， n=35）， Li （17.53 mg/L， n=64）， Br （72 mg/L， n=70）， and Cl （12 578 mg/L， n=70） in flowback water are basically lower than that of formation water. While the content of B （38.2 mg/L， n=64） in flowback water is similar to that of the Permian and Triassic formation water， but lower than that of the Sinian and Cambrian formation water. The ratio of B/Cl， Li/Cl and Na/Cl of flowback water is higher than that of formation water， but the ratio of Ca/Cl and Br/Cl of flowback water is lower than that of formation water. The flowback water， hydraulic fracturing fluid and Cambrian formation water has very good linear dependence between the contents of Br and Cl （R2=0.967 3）， which implies that flowback water was a mixture of the hydraulic fracturing fluid and the saline formation water retained in Silurian shale and the brine in this formation is similar to that in the Cambrian. Because of the dolomitization， formation water has the characteristic of enriched in calcium and depleted in magnesium， therefore， the flowback water also has such characteristic. Compared with the standards for drinking water quality （GB 5749-2006）， the contents of sodium， chlorine， boron， barium， manganese， iron， thallium， SO42- and TDS of flowback water， are much higher than that of the former， which have potential impact on the environment and cannot be directly discharged. The treatment of flowback water in Weiyuan mainly adopts the recycling method. If the chemical composition of the main and trace elements in the flowback water can be targeted for preliminary treatment before recycling， the influence of the complex components of the flowback water on the shale gas production and exploitation difficulty can be reduced， so as to greatly improve the feasibility of this method. The study of chemical composition difference between shale gas flowback water and conventional formation water and its potential environmental risk provides important scientific basis for treatment of flowback water and pollution prevention and control.
Three clay minerals of kaolinite， illite， and chlorite are selected and mixed with type I， type II and type III kerogen in different proportions， and the pyrolysis experiment is carried out. And the effects of mineral type and content on pyrolysis parameters of different type of source rocks are discussed. The results showed that clay minerals have interlayer adsorption and surface adsorption for hydrocarbon generation of kerogen pyrolysis. Surface adsorption will increase the catalytic ability of clay minerals. But interlayer adsorption will cause large molecular hydrocarbons to be adsorbed and precipitate between layers， inhibiting the formation of pyrolytic hydrocarbons（S2）. Small hydrocarbons are not easy to be adsorbed between layers. Therefore， kaolinite， illite， and chlorite act as catalyst for the formation of free hydrocarbons（S1） from types I， II， and III kerogen. Mixed sample of clay mineral and kerogen produced more S1 than pure kerogen. In addition， macromolecular hydrocarbons are susceptible to catalytic cracking into small molecular hydrocarbons， leading to S2 peak forward， which reduced Tmax value of kerogen. And as content of clay mineral increases， value of Tmax decreases. Illite and chlorite have interlayer adsorption， and type I kerogen has good parent material and tends to generate macromolecular hydrocarbons. Therefore， illite and chlorite have stronger interlayer adsorption effect on pyrolysis hydrocarbons of type I kerogen. Mixed sample of clay mineral and kerogen produced lower S2 than pure kerogen. This kind of interlayer adsorption causes S2 peak to lag behind， leading to higher Tmax of type I kerogen.
A large number of marine crude oil cracking gas fields have been found in Sichuan and Tarim basins， and continental crude oil cracking gas has also been found in Bohai Bay and Qaidam basins. However， there is not enough research on the mechanism of continental crude oil cracking gas， the main controlling factors and the difference between continental crude oil cracking gas and marine crude oil cracking gas. In this paper， a closed system gold tube pyrolytic experiment was used to simulate the pyrolysis of continental crude oil samples. The results show that： （1） Continental crude oil can generate a lot of pyrolytic gas in the high thermal evolution stage， and the RO value corresponding to the main gas generation period of continental pure crude oil series is 1.7%-3.3%. （2） The RO values corresponding to the main gas generation period of sandstone media series are 1.7%-2.6%， which can catalyze the cracking of continental crude oil. （3） There are three stages in the process of continental crude oil cracking： the initial cracking stage is when RO= 0.9%-1.6%， the massive cracking stage is RO= 1.6%-2.1%， and the exhaustion stage is RO= 2.1%-4.2%. （4） Carbon isotopes of pure crude oil under the medium of pure oil and sandstone show similar changes with the increase of temperature. Carbon isotopes of ethane and propane are reversed in the late stage of crude oil cracking. With the development of deep exploration， more and more continental oil cracking gas reservoirs will be found. Therefore， it is important to study the gas generation mechanism and gas production characteristics of continental crude oil cracking gas to find and discover large-scale continental crude oil cracking gas fields or reservoirs.
Recent years, as the improvement of isotopic analysis technique, lithium isotopes are widely used in tracing various geologic evidences. This paper gave a short introduction about the unique geochemistry character of lithium and lithium isotope of all kinds of lithium reservoir in nature. Besides, we analyze the fractionation mechanisms of lithium isotope during the geologic process under deep environment, summary the advance of lithium isotope in tracing weathering and subduction process, as well as, we also give a discussion about the distribution of lithium in various reservoir during the circulation of deep substance. Finally, combining the research of the influence that volcanic activity exerted on organic matter enrichment, this paper proposed that lithium may have great potential in identifying “water?carrying type” tuff and “airborne type” tuff.
Based on the analysis of main oil-source， evaluation of geological setting and controlling factors of hydrocarbon accumulation， combined with core observation， thin section identification， well logging and core logging， physical property data， this paper studied formation conditions and main controlling factors of hydrocarbon accumulation of the upper Wuerhe Formation of Permian in Zhongguai Uplift， Junggar Basin. The results show that Zhongguai Uplift， set in the high part of regional location， developed three large hydrocarbon generating centers， which results in abundant petroleum resources and becomes the dominant migration direction area of oil and gas. Hydrocarbon accumulation is controlled by the favorable reservoir-caprock combinations composed of sub-aqueous distributary channel conglomerate and their superimposed pro-fan delta mudstone microfacies， lacustrine mudstones in the upper Wuerhe Formation. Five effective reservoir traps under the dual control of structure and formation are formed. Therein， adequate and stable supply of oil source， the dominant migration direction is the physical basis of hydrocarbon accumulation. The development of fan delta sedimentary system and conglomerate reservoirs controls the scale of oil-gas pool， the stratigraphic unconformity- faults-overlap pinchout traps in updip direction control the vertical distribution of oil and gas.
The Permian and Triassic systems in slope area of Well Pen-1 Western Depression have a good source-reservoir-cap assemblage， which is an important area for the exploration of primary oil and gas reservoirs. The preliminary exploration is mainly based on the middle and shallow strata and mainly focuses on the search for secondary efficient oil and gas reservoirs. It is considered that the Permian and Triassic strata have not been used as the main exploration strata due to the large burial depth and undeveloped reservoirs. In recent years， the discovery of Mahu large oil area has provided important enlightenment for basin fan body exploration. Based on the exploration experience of Mahu， this paper makes a systematic study of the conditions of Permian and Triassic hydrocarbon accumulation in this area， and further deepens the geological understanding and enhances the resources and exploration potential through the overall evaluation of fan body， reservoir， unconformity surface and fault system. Studies have shown that there are two sets of high-quality source rocks of the Permian Fengcheng Formation and the lower Wuerhe Formation in the Well Pen-1 Western Depression. Permian and Triassic large-scale effective conglomerate reservoirs are developed. The complex oil and gas transmission system is composed of faults， unconformities and sand bodies. Regional and local mudstone capping， plain dense occlusion zone and faults constitute multiple capping preservation conditions， which laid a formation of large oil and gas fields. Three hydrocarbon accumulation models are established， namely， lower source and upper reservoir of the upper source-， new source to old reservoir of side source， self-generation and self-accumulation in source， and the hydrocarbon enrichment law under different models is proposed. Permian and Triassic of the Well Pen-1 Western Depression are favorable areas for hydrocarbon migration and accumulation. Multi-layered series are vertically stacked，high-quality reservoirs are connected in plane，and multiple collection types. It has great resource potential and low exploration degree. The upper and lower Wuerhe Formation of Permian and Baikouquan Formation of Triassic are selected as the breakthrough points for oil and gas exploration to achieve a comprehensive breakthrough of Permian in the central depression of Junggar Basin.
The Middle Permian is important for hydrocarbon source rock evaluations and shale oil explorations in northeastern Junggar Basin. The Lucaogou Formation and Pingdiquan Formation contain high-quality source rocks in eastern Junggar Basin， which have been tectonically separated by the Sha-qi Uplift. Although there have too many studies on shale oil in the Lucaogou Formation， few studies have been carried out on the Pingdiquan Foramtion in the vast area along the Kelameili Mountains. Well Shishu 1 has full core successions in the Pingdiquan Formation. Based on lithological analyses， and studies on data of source rocks， e.g. TOC， S1 and S2， this study focuses on the following items： source rock evaluations， vertically distributions and prospects of shale oil exploration. The following conclusions have been obtained： （1） The Pingdiquan Formation can be considered as a third-order sequence， which corresponds to combination of the Lucaogou Formation and the Hongyanchi Formation in southern Junggar Basin， and high-quality source rocks are developed in the middle and upper parts of Lower Pingdiquan Formation， which corresponds to the middle and upper Lucaogou Formation. （2） The source rocks in the Pingdiquan Formation have high content of mineral analcime， which is different from that of Lucaogou Formation； the organic matters in the Pingdiquan Formation are mainly algae and the kerogens are dominated by Ⅰ and Ⅱ1 types， which are the same to those in the Lucaogou Formation. （3） Source rocks in the Pingdiquan Formation are blocky， and laminations do not develop； hydrocarbon was not easy to be expelled， and fine-grained rocks can be considered as “self-generation and self-accumulation” in the lower Pingdiquan Formation along Kelameili Mountains.
In the Tazhong Uplift of Tarim Basin， the discovery of high yield oil of 3rd and 4th members of Ordovician Yingshan Formation reveals two new hydrocarbon reservoirs， which indicate broad prospect for exploration. But the coexistence of successful and unsuccessful drillings makes it difficult to determine the pattern of hydrocarbon accumulation， and how to find favorable zones becomes the core problem of efficient exploration. In this paper， the major controlling factors of hydrocarbon accumulation is studied by drillings， high quality 3D seismic data and the field outcrop with corresponding geophysical techniques. According to this， the favorable zone of accumulation was predicted. The research results show that， Cambrian source rocks are the main source of oil in the area， adjacent hydrocarbon generation depression is the most favorable material basis for hydrocarbon accumulation. Grand Ⅰand Ⅱ northeast trending slide faults break through the whole area， which communicate deep cold warfare hydrocarbon source rock effectively. And the slides play an effective path for lateral dredging and vertical adjustment of hydrocarbon. Because of the segmented activity intensity， the pinnate fracture zone is the dominant area for hydrocarbon accumulation. The tight limestone of the 1st and 2nd members of Yingshan Formation and the several hundred meters mudstone of the Sangtamu Formation prevented the upward escape of oil and gas， which is another guarantee for oil and gas accumulation. Based on the above understanding， the forward modeling is used to analyze the seismic emission characteristics of fracture-body reservoir， which is in good agreement with the drilling， so as to determine the favorable exploration zone and provide the technical support for the exploration.
The study of adsorption heat plays an important role in studying the mechanism of methane adsorption by coal. The gravimetric method was used to conduct 303 K， 308 K， and 313 K isothermal adsorption experiments on two sets of coal samples， and the equivalent adsorption heat of methane adsorption by coal was calculated， and the thermodynamic properties of coal adsorption of methane were analyzed. The research results show that the calculated isometric heat of adsorption is 30.51 kJ/mol and 23.14 kJ/mol in the experimental temperature and pressure and corresponding adsorption capacity， respectively， indicating that the adsorption of methane by coal belongs to physical adsorption； the increase in adsorption capacity increases monotonously and slowly， which is the result of the dominant interaction force between the adsorbed methane molecules； the 318 K isothermal adsorption characteristics are predicted using the 303 K and 313 K isothermic adsorption heat data， which is compared with the laboratory measured isothermal adsorption data. The two groups have the same trend. The relative errors of the two groups of coal samples are between 2.26%-5.72% and 0.29%-2.19%， respectively. A new method is proposed for using isosteric heat of adsorption to predict isothermal adsorption characteristics under different temperature and pressure conditions.
Marine shale of Lower Cambrian Hetang Formation from Well RDZ01 in Xiuwu Basin is selected to study the reservoir and its gas-bearing characteristics by organic geochemical analysis， petrology， porosity， low temperature N2 adsorption， CO2 adsorption and supercritical CH4 isothermal adsorption. RO value ranges from 1.74% to 2.32%， with an average value of 2.10%， and the maturity of organic matter is high. The total organic carbon （TOC） content is high， with an average of 3.21%. Main components are quartz and clay， 52.66% and 35.56%， respectively， with a small amount of feldspar， carbonate rock and pyrite are developed. Open cylindrical， layered slit and ink bottle pores are mainly developed in shale， with low porosity （2.05%） and average pore size of 8.416 nm. Specific surface area （SSA） and pore volume are generally high， ranging from 6.94 m2/g to 46.48 m2/g and 0.004 2 cm3/g to 0.020 1 cm3/g， respectively. SSA of micropores is large， which is close to that of Longmaxi Formation shale in Sichuan Basin， indicating a sufficient gas storage space. Study area has a good material basis for shale gas generation， and the shale has a strong CH4 adsorption capacity （average 1.71 m3/t）. The main influencing factors are TOC content and pore structure， and quartz is the favorable factor， while clay minerals have little effect. Shale in the study area is characterized by large thickness， shallow burial depth， type I organic matter， strong hydrocarbon generation ability and high content of brittle minerals， having good shale gas exploration potential.
The western Hubei and Hunan areas are one of the potential areas for marine shale gas exploration and development in the south，while the Lower Silurian Longmaxi Formation is one of the favorable shale gas intervals. In this study， the pore structures of shale samples from four coring wells in this area were characterized qualitatively and quantitatively by FE-SEM， low-temperature and low-pressure N2 and CO2 isothermal adsorption experiments.The experimental results show that there are abundant of interparticle pores， intraparticle pores， organic pores， compound pores of organic-clay minerals， as well as cleavage cracks in the shale， among which the most developed are interparticle pores of clay minerals and autogenous minerals， compound pores of organic-clay minerals and organic pores.The specific surface area of the shale is from 8.038 m2/g to 24.552 m2/g， with an average of 13.769 m2/g. The median diameter of the BJH pore diameter is from 8.21 nm to 13.79 nm， with an average of 10.43 nm. The largest pore diameter of Well LY1 is 11 nm， which is caused by the development of structural fractures in the well.
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