The study of the factors affecting the movable fluid of tight sandstones can effectively improve the accuracy of reservoir development potential evaluation. The typical tight sandstone samples of Shanxi Formation in the eastern Ordos Basin were collected， and the effects of clay minerals and pore-throat characteristics on the movable fluid were analyzed by using multiple tests， including thin section petrography， scanning electron microscopy， X-ray diffraction， rate-controlled porosimetry， and nuclear magnetic resonance. Based on the pore types， the tight sandstones were divided into three types as follows： （a） Intergranular pore-dissolution pore-intercrystalline pore type （type-I）； （b） Dissolution pore-intercrystalline pore type （type-II）； and （c） Intercrystalline pore type （type-III）. The contents of movable fluid saturation （MFS） of sandstones ranged from 9.39% to 78.79%， with an average of 41.63%， and had a moderate positive correlation with permeability. The study showed that the clay minerals were not conducive to movable fluid， and the pores larger than 200 μm and throats larger than 1 μm were conducive to fluid mobility. The high content of illite occurred as pore-bridging phases， which played a significant role in inhibiting fluid mobility. The type-I sandstones had high MFS values， of which the pores greater than 200 μm occupied a relatively high proportion， and the throats greater than 1μm occupied more than 50%. The contents of MFS in type-II sandstones varied greatly. However， with the increase of dissolution pores and the decrease of intercrystalline pores， the binding on the fluid caused by the pore-throats was weakened， resulting in the increase of the MFS values. The type-III sandstones were dominated by pores less than 200 μm， and throats less than 0.5 μm accounted for more than 50%. Thus， the contents of MFS in type-III sandstones were extremely low.

In the development of coalbed methane （CBM）， the inflow performance is an important basis for formulating a reasonable production system， which can maximize the stable production time and improve the final production. Aiming at the problem that there is no explicit equation of bottom hole pressure and multiple factors to evaluate the unsteady inflow performance， an explicit calculation model of bottom hole pressure and time， stress sensitivity coefficient， skin coefficient， total production， and start-up pressure gradient is established by using theoretical derivation and multiple factor fitting methods. The model is verified with production data， and the factors affecting the bottom hole pressure are analyzed. The results show that the accuracy of the model can reach 82.3%-94.76% from the initial production stage to the stable pressure stage， which can effectively evaluate the influence of various factors on production and bottom hole pressure， and provide technical support for optimizing the drainage system.

There are growing UHTP condensate gas reservoirs that have been discovered with the increase of exploration depth of offshore gas reservoir in recent years. The production of condensate water in these HTHP condensate fields increases significantly in the later stage of production， which makes it more difficult to analyze production dynamics and treat surface condensate water. In this study， experiments on the change of PVT water-gas ratio during development and the evaporation of formation water in long cores with decreasing reservoir pressure were conducted for three well areas in the abnormally high-pressure and high-temperature condensate reservoirs in the South China Sea. The difference of the condensate water-gas ratio of the three well areas with the decrease of gas pressure was compared， and the change characteristics of the condensate water-gas ratio obtained by the PVT test and the long core test under the formation temperature were discussed. The mechanism of formation water evaporation in long core simulating reservoir conditions is analyzed， which is higher than that in PVT cylinder. The simulation and prediction method of high-temperature condensate gas reservoir condensate water gas ratio is established and verified. The study shows： The fundamental reason why formation water evaporation in high-temperature and high-pressure condensate gas reservoir is higher than that in PVT cylinder is that the small pore diameter in the reservoir causes the critical properties of each component of condensate gas to deviate under the influence of pore diameter， which not only leads to the contraction of condensate gas in porous media， but also increases the saturated vapor pressure of formation water， resulting in the rise of dew point， and enhancing the mass transfer of formation water to condensate gas. The simulation and prediction method of formation water evaporation in high-temperature condensate gas reservoir can accurately predict the change of condensate water production.

The cross-scale storage and seepage media in carbonate reservoirs are distributed horizontally and vertically， with strong heterogeneity， which leads to complex gas production rules of gas wells. Therefore， it is necessary to explore the main controlling factors of gas well productivity by combining indoor physical experiments and mathematical model calculations on the basis of grasping the law of reservoir seepage. To this end， the gas seepage experiment under the original reservoir condition was first carried out， and then the quasi-threshold pressure measurement experiment， high-speed non-Darcy coefficient measurement experiment and stress sensitivity experiment were carried out in a targeted manner， and finally a trinomial capacity equation considering high-speed non-Darcy effect， low-speed non-Darcy effect and stress sensitivity was established. The numerical calculation results show that： （1） The productivity of gas wells is directly related to the type of reservoir. Fractured-cavity reservoirs have the best quality. Although the seepage capacity of porous reservoirs is weak， they still have certain exploitation value； （2） Stress sensitivity and high-speed non-Darcy effect should be considered in fracture-cavity reservoirs， and the combined effect of the two results in a loss of productivity of 41.82%； （3） The low-velocity non-Darcy effect of the vug-type reservoir is weak. If only stress sensitivity is considered， the resulting productivity loss is 12.53%； （4） Porous reservoirs have weak stress sensitivity. If only the low-velocity non-Darcy effect is considered， the resulting productivity loss is 23.42%. The above research results have important guiding significance for rational production allocation of gas wells in Dengying Formation gas reservoirs of Anyue Gas Field of Sichuan Basin and dynamic prediction of gas reservoir production and development.

For the tight sandstone reservoirs in the Ordos Basin， where the rock is compact， heterogeneous and the fracture shapes formed by conventional fracturing techniques are monolithic， a 3D reconstruction of the reservoir cannot be achieved. We have carried out the research on the law of balanced fracture initiation and extension of multi-cluster fracturing fractures in unconventional fracturing technology. Using the large size true triaxial simulation experiment system， based on the dimensional analysis method （π theorem） physical simulation experiment similarity criterion design， through multiple experimental proportioning， curing， mechanical testing and other methods， the artificial curing rock mass with mechanical parameters similar to the target layer is obtained， and a 30 cm × 30 cm × 30 cm artificial sample system was used to carry out the physical simulation experiment of unconventional volumetric fracturing. Taking the conventional fracturing technology as a reference， by changing the experimental conditions and design parameters， the non-equilibrium initiation and extension behaviors of fracturing fractures under five unconventional volume fracturing technologies， namely hydraulic pulse pretreatment， temporary plugging between clusters， flow limiting method， cyclic loading and unloading and pulse intermittent fracturing， were simulated， and the non-equilibrium initiation and extension laws of multi-cluster fractures were clarified. Compared with conventional fracturing， which has stress interference on the fracture and inhibits the fracture expansion， five unconventional volume fracturing methods can reduce the stress interference of multi-cluster fracturing， which is conducive to the uniform fracture initiation and expansion， and it is easier to obtain complex fractures and larger reconstruction volume. Among them， the effect of complex fracture networks is the best for inter-cluster block fracturing. It has developed and refined a balanced fracture and extension control technique for multiple cluster fractures in bulk fracturing， which has helped to improve the degree of 3D reconstruction of unconventional tight oil and gas reservoirs.

To address the difficult problem of poor understanding of the reservoir mobilization law of water-bearing sandstone gas reservoirs， a multi-point piezometric physical simulation experiment method and apparatus were used for long cores. Six natural matrix cores with permeability levels of 0.047，0.064，0.154，0.175，0.602， and 1.74×10^-3 μm² were selected， and a series of physical simulation experiments of depletion extraction were conducted under the conditions of water content saturation of about 0%，30%，40%，50%，60%， and 70%， respectively. The effects of reservoir matrix permeability and water saturation on the instantaneous gas production， pressure drop curve and characteristics of the reservoir， as well as the degree of reserve utilization （R） at different development stages （end of steady production， abandonment conditions and ultimate conditions） were investigated. The results show that： （1） the gas production capacity of reservoir matrix and the degree of reservoir utilization are controlled by both reservoir matrix permeability and water content saturation， but the sensitive threshold value is different in different stages of gas reservoir development. （2） Based on the characteristic diagram of the degree of utilization under the abandoned condition， a set of reserve utilization classification evaluation boundary map is constructed with the reservoir permeability and water content saturation corresponding to 60% and 80% of the reservoir utilization degree respectively as the indexes， and three levels of priority utilization， conditional utilization and potential utilization are divided， and the reservoir parameters corresponding to each level are clearly defined， which can provide prospective guidance for prioritizing and determining the sequence of reservoir utilization for high-quality reservoirs in the field.

Aiming at the thin interbeds of gravity flow sandstone in organic-rich shale layer of the 7th member of Triassic Yanchang Formation （Chang7 Member） in Ordos Basin， PetroChina Changqing Oilfield Company realized the cost-effective development of interbedded shale oil in continental low-pressure freshwater lacustrine basin， discovered and proved the 1 billion ton Qingcheng shale oil field， and presented proven reserves of 10.52×10⁸ t. It took the lead in building China's first one million ton shale oil integrated development zone. With the continuous expansion of production and construction scale， the difference of geological body is obvious， and the problems of low initial production and rapid decline of single well， low recovery efficiency and high development cost become more and more prominent. Through many years of field practice， the key problems in shale oil development are put forward， and reasonable suggestions are put forward according to systematic analysis. The drilling rate of shale oil horizontal wells can be divided into longitudinal drilling rate and transverse drilling rate. Improving the longitudinal drilling rate and transverse drilling rate of high-quality reservoir is an important measure to increase the production of a single well. When deploying horizontal wells， priority can be given to the extension direction of high-quality reservoirs to improve the drilling rate of high-quality reservoirs. The contribution ratio of elastic energy of fracturing fluid to recovery is relatively low， so the reservoir reconstruction should not overemphasize large sand volume， large fluid volume， and large displacement， but should fully consider well spacing， longitudinal interlayer distribution， and fracture development， and optimize fracturing scale， construction displacement and other parameters. The change of source rock quality and the strength of diagenesis are the main reasons for the difference of oil content in sand bodies， which affect the selection of favorable areas and the distribution of high-quality reservoirs. Pre-CO₂ volumetric fracturing has obvious energy increase effect， which is an effective means to reduce viscosity and improve oil recovery. It is an important measure to ensure the efficient development of shale oil in Changqing Oilfield Company by deepening the comprehensive geological research， clarifying the main controlling factors of differential shale oil accumulation， elaborating the three-dimensional sweet spot distribution， and exploring more effective development methods.

Multi-layer commingled production is the main feature of gas well development in Sulige tight sandstone gas reservoirs， Ordos Basin. Whether there is interference between layers and how to characterize them are important issues for effective development of gas reservoir. The physical simulation experiment process and scheme of interlayer commingled mining with fracture communication are designed， and the development simulation experiment of different interlayer combination modes is carried out. The results show that in the process of multi-layer commingled production of tight gas and water layers， whether it is only gas layers production or gas and water layers production at the same time， there is a common phenomenon of cross flow of gas and water between layers， resulting in interlayer interference and reducing the recovery of gas reservoirs. Based on this， the concept of interlayer interference index in multi-layer commingled production in tight sandstone gas reservoirs is proposed， and the interference index model is obtained by fitting the multiple linear regression method. The interference index is related to the physical properties of the reservoir. High water saturation and great permeability ratio of water layer to gas layer （greater than the critical value 1） can result in the early occurring of interlayer interference and great interference index. Finally， based on the interference index model， a new method for productivity evaluation of gas wells in tight gas reservoirs is established. The calculation results show that the interference index curve can effectively describe the interlayer interference performance of gas wells. The productivity and production performance of gas wells calculated by the productivity evaluation method based on the interference index model are consistent with the production history， which proves the effectiveness and accuracy of the interference index model. Therefore， the interference index model can effectively predict the productivity and production performance of gas wells in Sulige tight sandstone gas reservoir. The research results have important theoretical guidance and practical significance for the efficient development of Sulige tight sandstone gas reservoir.

The degree of fracture development is the main controlling factor for high production and water invasion of ultra-deep gas reservoir in Tarim Basin， but there are few studies on the division of fracture development model among different gas reservoirs and its effect on static gas-water distribution and dynamic water invasion. Taking Keshen 2，9 and 8 gas reservoirs as examples，the typical ultra-deep gas reservoirs in Tarim Basin，as the main research object，based on the outcrop，core，FMI，mud loss，well test interpretation and production data， combined with water invasion physical simulation experiment and gas reservoir development practice verification， the gas-water distribution and water invasion law of gas reservoirs under different fracture development models are systematically studied.The results show：（1）Three fracture models are developed in Keshen 2，9 and 8 gas reservoirs， namely direction type， transition type and fracture network type， respectively. The fracture occurrence of each gas reservoir is basically the same， and the mean values of static and dynamic parameters of fracture quantitative characterization， such as fracture size， effectiveness， physical property， open flow rate and mud loss amount， as well as the degree of difference between wells increase successively.（2）The gas-water distribution is mainly controlled by fracture development model， and the gas-water differentiation degree increases gradually in Keshen 2， 9 and 8 gas reservoirs， corresponding to three gas-water distribution models of thick gas-water transition zone， thin gas-water transition zone and normal gas-water differentiation respectively.（3）The fracture development model determines the water invasion rate and recovery factor. The non-uniform water invasion rate of Keshen 2 gas reservoir is fast， and the water flooding efficiency of the physical simulation is low， and the ultimate recovery factor of gas reservoir is low. The water invasion law of Keshen 8 gas reservoir is opposite， and Keshen 9 gas reservoir is in the middle. The research results can provide theoretical model and geological guidance for the formation of water control development and EGR technology in gas reservoir life cycle

The objective of this study was to investigate the effects of the development degree of carbonate dissolved pores and gas injection velocity on the gas-water two-phase seepage. An interparticle-dissolved dual-pore network model was proposed using a convolution algorithm by considering the characteristics of carbonate karst pores. The proposed unsteady-state gas-water seepage model took the effects of gas compressibility and pore-scale pressure propagation into account， and it was validated by comparing the simulation results with the core-derived gas-water two-phase seepage through unsteady-state gas flooding experiments， which comprehensively characterizes the pore-scale gas-water seepage flow in pore-scale modeling. The gas flooding procedure at different injection velocity was simulated by assuming different characteristics of dissolved pores in carbonates. The results indicated that the more developed dissolved pores can bring about a wider gas-water two-phase infiltration area and a longer gas-water co-flow period. Further， the competitive balancing between the gas injection pressure and the capillary and viscous forces could also impact gas sweeping efficiency， resulting in different gas-water spatial distributions， gas injection velocity and pressures. The results provided a deep technical and theoretical view of the gas production in carbonate reservoirs， which has important significance for improving the exploitation efficiency of carbonate reservoirs.

The gas reservoirs of the Qixia Formation in Shuangyushi area are the high temperature and high pressure gas reservoirs firstly discovered over 8 000 m in NW Sichuan Basin. Although it is another central accumulation area of carbonate gas reservoirs discovered in Sichuan Basin in recent years， the strong heterogeneity of reservoirs leads to the difficulty of deploying high productivity wells. Based on the results of reservoir evaluation and the dynamic and statistical analyses of the well test data in previous four years， this paper first uses the method of comprehensive analysis to establish the relations between geological and production， then uses fuzzy clustering analysis method to screen the evaluation index and establish the evaluation index system of the key controlling factors of high productivity in gas reservoir of the Qixia Formation in Shuangyushi area； finally， the relative importance of each index is quantitatively evaluated by AHP to determine the key controlling factors of productivity. In 2022， Wells Shuangtan X108 and Shuangyu 001-X9 were newly completed outside the pilot zone. Test productivity over one million cubic meters per day demonstrates that the evaluation results are in good agreement with the characteristics of current high productivity wells. The result shows that the high productivity of ultra-deep gas wells in the Qixia Formation is mainly controlled by the degree of dolomization and fracture development， the distribution of high energy shoal-mound complex， it can be used to guide the deployment of productive wells in the southern area of Shuangyushi producing test area.

With the rapid progress of shale gas exploration and development in southern Sichuan， it is necessary to drill infilling wells improving recovery factor or recovery efficiency. Using existing production wells to evaluate the Estimated Ultimate Recovery （EUR） of infilling wells has become one of the emerging problems. In this paper， the EUR of Weiyuan producing well has been predicted and its probability distribution has been established by using the Modern Production Decline Analysis Method. Based on the above results， EUR of infilling wells has been simulated by using the Mante Carlo probability method. It is considered that the development of Weiyuan shale gas has entered a mature stage from the statistical law of EUR of single well， and the EUR of infilling wells can be established in Weiyuan， and the probability method can be used to evaluate the EUR of infilling wells； The risk of infilling wells EUR evaluated by probability method in block W204 are much smaller， indicating that the more wells， the less uncertainty of EUR； After development of shale gas entering the mature stage， the probability method can give more reliable prediction of the single well EUR and reduce uncertainty risk of project. The results and methods of using probability method to evaluate infilling well EUR and gas field EUR in this paper can provide reference for other similar areas.

The ultra deep-buried fractured tight gas reservoir in Kuqa Depression, Tarim Basin has developed edge and bottom water. Faults and fractures have become the “highway” of water invasion, resulting in “water-sealed gas” effect and reducing gas reservoir recovery. At present, there is a lack of effective evaluation methods. Therefore, based on the analysis of water invasion characteristics of gas reservoir, a dynamic evaluation method of water-sealed gas in fractured gas reservoir considers two factors: fracture development scale and peripheral water body strength is established and applied to three developed blocks in Kuqa ultra deep layer. The effectiveness of the evaluation results is verified by static and dynamic combination, and the countermeasures to improve gas reservoir recovery are put forward. The results show that: (1) The non-uniform water invasion of fractures is jointly controlled by the structural position, fracture development degree and fracture network combination, which can be divided into three water invasion modes: The edge water channeling along the large fracture in the core, the edge and bottom water invading along the fracture in the wing, and the rapid violent water flooding of the bottom water along the fracture/small fault in the low part. (2) The replacement coefficient of water invasion in the three typical blocks is 0.2~0.3, which is sub active water gas reservoirs, but the severity of water sealed gas varies greatly. The more serious the water sealed gas is, the lower the recovery factor of the gas reservoir is. (3) For directionally penetrating large fracture gas reservoirs, field practice of water shutoff should be carried out. For fracture network gas reservoirs with high fracture density, mild exploitation can control water, and early drainage can reduce the impact of water invasion, so as to improve gas reservoir recovery. It is concluded that the new method of water-sealed gas dynamic evaluation can provide a reliable basis for the evaluation of fracture non-uniform water invasion dynamic of ultra-deep gas reservoir and enhanced oil recovery of gas reservoir in Kuqa Depression, and support the formulation of water control policy and economic and efficient development of ultra-deep gas reservoir group in Kuqa Depression.

Sulige tight sandstone gas field is characterized by poor reservoir physical properties, multi-layer lenticular reservoir structure, small scaled sand bodies and strong heterogeneity. That the existing well pattern has insufficient reservoir control results in low recovery factor. At present, the well pattern infilling adjustment is one of the most effective means to enhance the recovery factor. According to reservoir structure and gas well production effect, the recoverable reservoirs of the gas field can be divided into three types, corresponding to the reserves abundance of>1.8×10⁸ m³/km²， （1.3-1.8）×10⁸ m³/km²，（1.0-1.3）×10⁸ m³/km². Based on the production data of dense well pattern test area under different reservoir conditions, combined with analysis of reservoir scale and scope of gas well deflating evaluation, combining development efficiency and recovery factor enhancement, the suitable well spacing density comprehensive analysis was carried out from the perspectives of inflection point of recovery factor enhancement, overall development effectiveness of the well groups, and the break-even point of the infilling well. It is determined that the suitable well pattern density for type I, II and III reservoirs is 3, 4, and 4 wells/km², respectively. The scale of remained producing reserves of the gas field is 1.23 trillion cubic meters. If new well pattern is deployed there, compared with the 600 m×800 m well pattern, 12 000 more wells can be drilled, additional 45 billion cubic meters producing capacity can be built, another 200 billion cubic meters of gas will be produced. Then, the recovery factor will rise from 32% to 48.5%.

Ultra-deep carbonate gas reservoirs are deeply buried and high in temperature, and the change rule of high temperature on the seepage capacity of multi-type reservoirs is still unclear. The cores of the fourth member of Dengying Formation in the Gaoshiti-Moxi area were selected, the gas single-phase permeability of the rock samples during the heating and cooling process, the gas-water interfacial tension and the gas-water two-phase relative permeability at different temperatures were measured, and then the effect law of temperature on the seepage capacity of the multi-type ultra-deep carbonate gas reservoir was obtained. The research results show that: in the range of 20-120 ℃, with the change of temperature, the gas single-phase seepage capacity of different types of reservoir rock samples changes as a power function. The decrease of gas-phase permeability during the heating process is jointly affected by the increase of gas viscosity, the expansion of dolomite crystals, and the migration of rock particles after embrittlement. After one heating and cooling process, the irreversible degree of permeability of fractured-cavity type rock samples was the highest at 82.52% due to the development of micro-fractures, followed by 27.63% for pore type due to the development of small pores and throats, and the lowest was 9.46% for pore-cavity type. Fractured-cavity rock samples are temperature-sensitive rock samples, while pore type and pore-cavity type rock samples are temperature-resistant rock samples. The upper temperature limit of the target multi-type gas reservoir is concentrated around 46-50 ℃. The temperature increase mainly improves the gas-displacing water efficiency and the gas-water two-phase seepage capacity by reducing the water-gas viscosity ratio and the water-gas viscosity ratio at the formation temperature is about 1/3 of the normal temperature. The gas-water phase permeability curves of multi-type reservoirs under high temperature conditions can better represent the two-phase seepage characteristics of actual formations. The effect law of temperature on the seepage capacity of multi-type ultra-deep carbonate gas reservoirs can provide a theoretical basis for the efficient development of such gas reservoirs.

The Quaternary unconsolidated sandstone gas reservoir in the Qaidam Basin is characterized by multiple layers， strong heterogeneity and active edge-water. Based on these characteristics， a physical simulation experiment method for production from multi-layer edge-water gas reservoirs was proposed. In this method，the experimental models were established by using natural cores in series and parallel connection to show geological characteristics of multi-layer gas reservoirs. According to the indoor simulation results of the whole depletion production process，an experimental study on four layers commingled production in one well was conducted under three scenarios of gas reservoirs without the water invasion，with the water invasion without flow，and with the water invasion with flow. In this study，by visually monitoring the water invasion process of constant pressure edge water body along layers with different permeability，and quantitatively analyzing the influence of gas well production allocation on water invasion path and advancing speed of water invasion front，the influence of non-uniform edge water invasion on gas reservoir productivity，recovery factors and residual gas occurrence characteristics was clarified，and the mechanism of non-uniform edge-water invasion along high permeability layers and formation of water sealed gas were revealed. The findings of this study can provide a basis for reasonable water control for this type of gas fields.

According to the common production characteristics in the actual production process of oil and gas wells， the production decline model under the change of constant pressure production mode to the quasi-steady state of bounded reservoir is studied， which provides a new theoretical basis for defining the seepage mechanism of oil and gas well production decline. Based on Hiles and Mott’s mechanism， through theoretical derivation， a new production decline model is established when the bounded reservoir reaches quasi-steady state in the late stage of boundary flow， under the condition of a constant pressure production. The results show that the model is formally consistent with Arps’ decline model， and its three decline parameters have exponential correlation. However， compared with Arps’ production decline model， this model is more extensive and general. That is， when the exponential coefficient from Hiles and Mott’s constitutive equation is 1， which means fluid seepage follows Darcy's law， the production decline of oil and gas wells follows exponential decline， with the condition of pseudo steady state， because of boundary effect. When the exponential coefficient from Hiles and Mott’s constitutive equation varies between 0 and 1， the fluid is in the transitional state of Darcy flow and turbulence， and the decline curve is a power function decline， and specially when the exponential coefficient from Hiles and Mott’s constitutive equation is 0.5， which means the fluid is in a turbulent state， and the production decline curve of oil and gas wells is a straight line. When the exponential coefficient is greater than 1， which means fluid seepage is low-speed non Darcy flow， the production decline becomes a hyperbolic decline curve， and the three characterization parameters of hyperbolic decline have nonlinear correlation， and the decline model satisfies the law of mass conservation. This not only lays a theoretical foundation for the analysis and discrimination of fluid seepage characteristics in the quasi steady state stage of bounded reservoir， but also provides a scientific basis for reservoir parameter inversion using production decline model， which is of great significance for deepening and expanding the application of Arps’ production decline model， so it has strong practicability and foresight.

The second section of Sinian Dengying Formation in Anyue Gas Field has great potential to develop, which is an important producing area of Anyue Gas Field. This reservoir has low permeability and partly developed high-porosity-permeability section. The reservoir space mainly includes karst caves, dissolution pores and fractures. The bottom water is developed in the lower part of the reservoir and the gas-water interface is unified at -5 150 m. The deep acid-fracturing technique can increase well production for such carbonate gas reservoir with low-porosity-permeability. However, there are some difficulties in acidizing fracture controlling because of natural high-angle fractures, small stress difference between sections, and the short distance between the stimulation section and the gas-water interface. It is easy to connect with the lower water layer, causing water production after stimulation. In order to explore the controlling method of acidizing fracture height, the geological and engineering influencing factors of acidizing fracture height were simulated, and a pseudo-three-dimensional extension model of acidizing fracture height was established, which considered the influence of longitudinal pressure drop on fracture height propagation in the process of fracture height propagation. The results show that the interstage stress difference and displacement are the main controlling factors of fracture height extension, and the stress difference has the greatest influence on fracture height, followed by the thickness of reservoir and interlayer and the viscosity of working fluid. The simulation results of mathematical model revealed the controlling factors and model for acid-fracturing fracture height in different reservoir characteristics. In this paper, the design parameters of acidizing controlled fracture height are optimized. Under the premise of effectively controlling the height of acid fracturing fracture, the production of single well can be maximized and water can be avoided after stimulation, which provides theoretical guidance for deep acid fracturing technology of gas reservoir with bottom water.

In Demonstration Zone, the major target horizon of shale gas development is the five meters thick Lower Silurian Longmaxi Formation marine shale. It is characterized by small target window, big structural fluctuation and small fault development, so it is possible for the actual drilling trajectory to miss the targets and run out of the target layers. By analyzing the technical difficulties during the geosteering of horizontal wells, the solutions were worked out starting from the key points of target orientation and horizontal section geosteering. (1)The optimized model eliminates the four shortcomings of the traditional modeling theory, improves the accuracy of the model to predict the landing point, ensures that the well path smoothly enters the target, while avoiding entering the target too early or late, resulting in the regularity of the well path, which is “V-shaped” or “ladder shaped”. (2)It solves three major problems in the horizontal section geosteering, such as multiple solutions, encountering fault and fold by integrating techniques including element mud logging + gamma ray control while drilling, macroscopic seismic prediction, ant-tracking attributes, and the idea of “emphasizing serious cases and ignoring minor ones” to adjust the well path. It can ensure the precision in landing and tracking horizontal section, drill-in rate and smooth well path.

Taking shale gas platform well groups inter-well interference factors as the research object， using numerical well test analysis technology， the degree of impact of different reservoir matrix permeability， fracturing parameters， well spacing， activation intensity and other parameters on inter-well interference are studied. On this basis， the pressure distribution characteristics of shale gas horizontal wells at different production times were grasped， and the degree of impact of inter-well interference on gas wells’ EUR was clarified， and well spacing optimization was formed that comprehensively considered gas wells’ EUR and well-controlled geological reserve recovery factor analytical method. The results show that when the natural fractures are not developed and the artificial fracture network between wells is not communicated， the propagation range of pressure waves outside the reconstruction area is limited， and the interference intensity between well groups of shale gas platform well groups is generally weak. The pressure drop degree is the largest in the fractured zone and around. When optimizing well spacing， it is necessary to consider not only whether there is pressure interference response between wells， but also the intensity of pressure interference； the more natural fractures develop and the greater the range of fracturing reformation， the more obvious the interference between wells， and optimization well spacing should take into account the development of natural fractures and the impact of fracturing reconstruction range； affected by inter-well interference， the EUR of gas wells increases with the increase in well spacing， but the increase gradually decreases， and the recovery rate decreases with the increasing well spacing. It is necessary to optimize the well spacing based on the geological engineering characteristics of the platform well group， comprehensively considering the gas wells’ EUR and the well-controlled geological reserves recovery factor.

Qixia Formation gas reservoir in Shuangyushi area is a complex carbonate gas reservoir with ultra-deep layer in the northwestern Sichuan Basin. The gas reservoir characterization of different reservoir infiltration types and their development response models are not clear， which restricts the scientific and efficient development of gas reservoir. In this study， core observation and thin section identification were used to identify the basic reservoir characteristics. Firstly， cluster analysis was carried out using conventional logging curves which are highly sensitive to reservoirs to classify the reservoirs. Secondly， combined with the quantitative characterization parameters of macro and micro static pores， cavities and fractures， such as CT scan and mercury injection， the reservoir and permeability characteristics can be divided into three categories. Finally， based on the static and dynamic response characteristics of the reservoir and seepage type， a targeted development response model is formed. The research shows that： （1） Four types of dolomite reservoir develop in Qixia Formation， and the fracture-cave type， fracture-pore type are high-quality reservoir types. （2） The reservoir classification index and spatial distribution characteristics of high-quality reservoirs are defined， and the reservoir and permeability types of gas reservoirs are further divided into three types， among which the first and second types of reservoir infiltration characteristics are medium-high production wells. （3） There are two kinds of gas reservoir development response modes： macro heterogeneous， micro heterogeneous and macro visual homogeneous. The production capacity of the two modes is strong， but the production effect is different， the gas reservoir scientific development can be realized. The research method of the combination of gas logging-geological-development and static-dynamic development is of reference significance for the description of reservoir infiltration type and the optimization of the development mode of the same type of ultra-deep layer carbonate gas reservoir.

Productivity is the core index to evaluate the development effect of shale gas field， and the comprehensive nonlinear effect of high-pressure physical property， supercritical desorption， multiple micro-flow mechanism and stress sensitivity of shale gas can’t be ignored in its contribution to productivity. In this paper， based on the conventional five-zone compound flow model， a comprehensive consideration was given to gas nonlinearity and the stress sensitivity， an improved compound linear flow model was established and a semi-analytical solution for productivity was obtained. Then， the reliability of productivity solution was verified through examples and important influencing factors were clarified. The results indicated： （1）The model comprehensively considers the impact of nonlinear effects on gas production so as to predict the medium- and long-term productivity of gas wells accurately. （2）The greater the main fracture half-length， the greater the productivity， so long fractures should be designed as much as possible； too high or too low the cluster spacing and conductivity of the main fractures do not significantly change the extent of reservoir utilization， so the values of the cluster spacing and conductivity of the main fractures in this paper can be preferably around 10 m and around 4.0×10^-15 m³； the greater the stress sensitivity coefficient， the lower the productivity， and the proppant with excellent performance should be selected or the fracture slip surface should be designed to improve the fracture conductivity. （3）The significance of horizontal well spacing and horizontal well length on improving the utilization of shale reservoirs is considerable. In actual production， the horizontal well spacing can be optimized to 500 m， and horizontal well length of 2 000-3 000 m can also be adopted for technical research.

Taking the reservoir rocks of sandstone gas reservoirs in China as the research object， combined with high pressure mercury injection and outcrop reconnaissance and gas field data analysis， taking pore throat radius， core permeability， well test permeability and logging permeability as indexes， this paper established the microscopic and macroscopic heterogeneity characterization methods of sandstone gas reservoir， and studied the heterogeneity characteristics of core micro pore throat， outcrop profile， block and gas field. The results show that the microscopic pore throat structure of sandstone gas reservoir is extremely complex， and the flow channel is composed of a large number of pores， fractures and throats of different sizes， forming a complex flow network which shows strong heterogeneity both microscopically and macroscopically. Combined with reservoir heterogeneity， the physical simulation model and method of heterogeneous full-diameter long core are established， and the production effects of well distribution in high permeability area and dense area are compared and studied. Under the condition of 800 mL/min rationing production， the stable production period of well distribution in high permeability area is 60% longer than that in tight area， and the production decreases rapidly after the end of stable production period， and the low production period is short； the formation pressure of well distribution in high permeability area decreases faster than that in tight area， indicating that reserves can be used more quickly； the recovery percent in high permeability area rises faster than that in tight area， and the recovery percent at the end of stable production period is 51.2% higher while the recovery is 14.6% higher. The research results are of guiding significance for the scientific development and enhanced gas recovery of similar gas reservoirs.

Accurate evaluation of the physical property limits is one of the key parts for efficient development of deep carbonate gas reservoirs. However， previous studies did not fully consider the influence of formation pressure and water saturation. For this reason， taking the deep carbonate gas reservoir of Longwangmiao Formation in Anyue gas field as the target， the influence of pore structure and irreducible water on gas flow was studied through core experiments under reservoir conditions. Then， a similarity transformation model considering the influence of start-up pressure gradient， stress sensitivity and pressure variation was established； and the physical property limits of dry and irreducible water reservoirs were evaluated. The results showed that pore structure， water saturation and production pressure difference are the main factors affecting reservoir productivity. Under the production pressure difference of 10-50 MPa， the permeability lower limits of reservoirs without water are between 0.420×10^-3 μm² and 0.049×10^-3 μm²， the irreducible water greatly reduces the gas production rate， and the permeability lower limits of reservoirs with irreducible water is twice that of reservoirs without water. This study will provide a reference for reservoir evaluation， productivity prediction and scheme adjustment of deep carbonate gas reservoirs.

Shale oil in Ordos Basin has the characteristics of low pressure coefficient， low brittleness index and vertical multi-interlayer. Horizontal well and volume fracturing technology can greatly increase the production of single well， but it is difficult to achieve economic and effective development under low oil price. On the basis of big data's field practice in the basin， a quantitative evaluation method of volume fracturing effect was established， which puts forward the volume fracturing transformation strategy and the direction of the next project. On the basis of the establishment of a new sectional classification evaluation standard for the comprehensive geological engineering quality of horizontal wells and the fine classification of reservoir types， and based on the test results of fluid production profiles of 112 sections of nine horizontal wells， it was concluded that the fracturing segments of I and II reservoirs account for 85.2%， and the output accounts for 96.4%， which was the main productivity contribution section. The fracturing segments of III reservoirs account for 14.8%， and the output accounts for only 3.6%， with the lowest contribution. Therefore， priority is given to fracturing type I and II reservoirs， and selective fracturing of III reservoirs. The main factors affecting productivity are reservoir length， fluid injection strength， fracture density， brittleness index， sand addition strength， permeability， discharge， porosity， horizontal stress difference and oil saturation. The material basis of reservoir is the first condition to obtain high productivity， and increasing the sweep volume of fracture net is an important way to maximize the productivity of unconventional oil and gas. The research results can provide a scientific basis for the optimal design of volume fracturing of shale oil horizontal wells and effectively promote the scale benefit development of shale oil.

Chang 7 Member shale oil reservoir in Ordos Basin， China is continental and shows characteristics of low porosity and permeability with poor reservoir connectivity. Oil displacement efficiency of this type is low， because water breaks through underground during water flooding. Shale oil in the basin has been developed by large-scale fracturing to increase water-oil contact thus to improve oil recovery rate. Oil recovered by water imbibition was proved to be effective， and both development practices and indoor experiments showed that shale oil recovered by water imbibition accounts for 15%-40% of the total， providing a new method for oil displacement in shale oil reservoir. In this study， open-boundary core system was used to quantitatively study the impacts of pore radius， interfacial tension and permeability on oil recovery by water imbibition underground. Indoor experiments showed that shale oil produced from pores with radius less than 10μm accounts for 56%-80% of the total； shale oil recovered by water imbibition peaks when interfacial tension is 1.18 mN/m； core permeability is positively correlated with imbibition recovery when interfacial tension is less than 2 mN/m， while the two are not significantly correlated when interfacial tension is higher than 4mN/m.

Previous development practices in Chang 7 Member shale oil reservoir have proved that individual well production in Qingcheng Oilfield is related to several factors in both geology and engineering， such as physical properties of a reservoir， lateral length， fracturing scale etc. However， the most decisive factors among those are not clear. This paper is outlined to study the dominating factors relating to individual well production， based on geological parameters， fracturing construction data， and production data. Productivity influencing factors are quantitatively ordered using gray correlation analysis method and random forest algorithm. Research shows that the most decisive factors affecting individual well production of a horizontal well are porosity， oil saturation， brittleness index， effective lateral length， number of fracturing sections， sand volume pumped into a single fracturing section， and the amount of fracturing fluid pumped underground. Thus， well displacement， lateral length and fracturing parameters are optimized. This study provides a guidance to the development of shale oil reservoir considering low oil prices nowadays.

As an important characteristic of shale oil and gas reservoir, bedding has a significant influence on vertical propagation of hydraulic fractures. Through theoretical analysis, innovation of large-scale hydraulic fracturing simulation experiment method, and field scale hydraulic fracture monitoring for shale oil and gas reservoirs, the vertical fracture propagation patterns under bedding condition are revealed, and the main controlling factors of fracture penetration are identified, which could guide the optimization of unconventional reservoir treatment. The experiments indicate that there are three different kinds of results when the fracture height reaches the bedding plane: crossing directly, crossing offsets and arresting (bedding slippage or dilation). Besides, the orthogonal analysis shows that the bedding strength is one of the most critical influences on fracture height. The field practice further confirms that weak bedding plane can arrest fracture height obviously and the fracture height also can cross the bedding because of strong bedding interface. In addition, the natural fractures on the plane and the difference of mechanical properties between layers also have significant influence on the fracture height. The research can provide technical support for the optimization design of hydraulic fracture vertical propagation under the bedding existence in unconventional reservoir.

Taking Deng 4 Member gas reservoir of Sinian system in central Sichuan Basin as an example, aiming at the main problems of the controlling factors of productivity and development strategies optimization in the early and middle stages of the highly heterogenous gas reservoir，the scientific connotation of the controlling factors of gas well productivity was studied，and the core elements and main research items of the controlling factors of productivity in different stages were put forward. Based on the six types typical seepage patterns of gas reservoirs, the early, transitional and stable stages were defined. On this basis, the countermeasures and suggestions were given in four aspects: Well location plane deployment, target location, transformation process and production well system optimization. The results show that: (1) The controlling factors of productivity refer to the main conditions that affect the productivity of gas wells, and the research objects and emphases are different in different development stages. The core elements are the implementation of reserve base, the seepage capacity of transformation area and far well area, and the main research items are the key indicators of high-quality reservoirs, seismic response, special well test interpretation technology, etc. (2)The regular production capacity of the early stage, transitional and stable stages of Deng 4 Member gas reservoir is controlled by the development of high-quality reservoir，the matching of fracture system after reservoir transformation，the gas supply capacity of far well area and the remaining dynamic reserves. And the influence of the electrical characteristics of high-quality reservoir, the characteristics of well test after transformation, construction curve, the plane heterogeneity and the variation of remaining dynamic reserves on the production capacity at different stages in the early and middle stages are clarified. (3)Through the implementation of development strategies optimization, the breakthrough of single well production has been achieved. The average absolute open flow rate of the new technology well were 2.3 times of the vertical well, the proportion of stable production increased from 80.5% to 95%, and the tubing pressure decline rate slowed down, which basically met the design requirements of the development scheme. The research results from the controlling factors of productivity in the early and middle stage and the development optimization technical countermeasures provide technical reference for the efficient exploration and development of ultra-deep strong heterogeneity carbonate gas reservoirs.

The microgravity monitoring technology is to convert the superposition field into the difference field， and obtain the more real information of the change field. The result has nothing to do with the single well point. It is the objective description of the overall density and fluid change of the oil and gas reservoir， and it is the overall monitoring of the oil and gas reservoir. It creates conditions for overcoming the multi-solution of interpretation， and its monitoring results are closer to the truth. Therefore， this paper proposes to use the microgravity monitoring results to describe the distribution of residual gas， and to evaluate the development well location and the development potential of residual gas. Firstly， the characteristics of gas bearing formation on microgravity abnormal section are analyzed. Secondly， the development well location evaluation and residual gas potential evaluation model are established. Finally， the microgravity monitoring technology is applied to the Su14 infilled well area， the remaining gas plane distribution is described， the development well location and the remaining gas development potential of the Su14 infilled well area are evaluated， and the next step of the remaining gas development comprehensive adjustment plan and countermeasures for potential tapping are proposed. The adjustment method carried out index prediction， and used the numerical simulation results of the Su14 infilled well area and the production performance analysis results of the development wells to verify the accuracy of the microgravity monitoring residual gas distribution results and the evaluation model.

Taking the tight reservoir of Fengcheng Formation in Mahu Depression as the research object， the RFPA software of the numerical simulation platform for the real fracture process was used to study the propagation and extension law of reservoir fractures around the well during the fracturing process. On this basis， the influence of rock mechanical properties and horizontal principal stress difference on the fracture extension law of the reservoir around the well is studied. Grey correlation method is used to quantitatively analyze the influence degree of each factor on fracturing effect， and combined with analytic hierarchy process， the evaluation model of reservoir fracturing ability is constructed. The results show that the larger the horizontal principal stress difference is， the more obvious the directionality of fracture extension is. The lower the fracture initiation pressure is， the larger the fracture extension distance is. With the increase of compressive strength， tensile strength and elastic modulus， the cumulative number of acoustic emission decreases， and the fracture extension distance decreases. However， with the increase of Poisson's ratio， the cumulative number of acoustic emission increases， and the fracture extension distance increases. Based on the grey correlation method， the order of influencing the fracturing effect was determined as the horizontal stress difference > elastic modulus > tensile strength > uniaxial compressive strength > Poisson's ratio. Using the analytic hierarchy process （AHP）， a model for calculating the reservoir fracturing index is established， which takes into account the influence of horizontal stress difference， elastic modulus， tensile strength and uniaxial compressive strength， etc.， and has a good positive correlation with the extension distance and area of non-dimensional fracture. Combined with the test data of the fractured well， there is a positive correlation between the fracturability index and the oil recovery intensity.

In order to clarify the law of fluid occurrence and gas water co-permeability in tight gas reservoirs， tight gas reservoirs in Dingbei block and Daniudi block were taken as the research objects， and the experimental methods of imbibition， centrifugation， NMR and gas water displacement were used to study the change and dynamic distribution of fluid content during fracturing and flowback， as well as the law of gas water two-phase flow during production. The results show that： In the process of fracturing， the spontaneous imbibition of tight gas reservoir cores to fracturing fluid is first fast and then slow. The fluid first enters smaller pores， then the fluid distribution becomes more concentrated. In the process of flowback， the fluid in larger pores is preferentially discharged， and some movable fluid becomes bound fluid. At the same time， there is a positive correlation between imbibition capacity， flowback rate and rock physical properties. The gas-water relative permeability curves of the Dingbei block have large irreducible water saturation and small co-permeability area. During the production process， the gas-water two-phase interference in the reservoir is serious， and the gas relative permeability decreases rapidly after water breakthrough

For the purpose of enhancing recovery and economics of shale resource，it is a critical task for petroleum engineers to determine the optimal well spacing in the industry development of shale play.By using various approaches including analogs，numerical simulation and economic assessment based on the theoretical understanding，this paper integrated interference response simulation based on multi-well pattern with history data matching to establish a comprehensive workflow for identifying production interference and optimizing well spacing.The workflow is threefold： firstly， a general semi-analytical model for the distance of pressure investigation was presented to calculate the interference time through fracture and rock matrix； secondly，a method of interference measurement was introduced to quantify production interference by searching for changes in buildup trends while wells are staggered on/off production； finally，a numerical model of coupling geological and fracture geometry information was proposed to optimize well spacing in multiple-well pattern with purpose of maximizing the objective function of net present value.In this paper， Ning 201 well block in Changning pilot area is taken for example， the simulation results show that ①fracture conductivity is more important in short-term production period， while fracture half-length becomes more significant at long-term production period； ②there is a potential of decreasing well spacing from 300-400 m to 260-320 m， with the increasing number of production wells by 20%-30% and enhancing recovery of reservoirs by 10%； ③the value of NPV would increase with the production period elongating， but the optimal well spacing kept constant regardless of the duration of production period.

Deep shale gas reservoirs are rich in reserves， but their closure stress is high， heterogeneity is strong， fluidity is poor. In order to characterize the heterogeneous fracture network form and the dynamic change of permeability in the stimulated area after volume fracturing in deep shale gas reservoirs， we obtained the binary image by CT scanning the artificial fractured core and calculated the fractal dimension， and used Monte Carlo stochastic modeling and statistics of the fracture parameters. Based on the principle of flow equivalence， the heterogeneous fracture network is decomposed. Coupling the shale gas viscous flow， the Knudsen diffusion， and the surface diffusion to establish single fracture flow equation and use fractal theory to upscale. At the same time， consider the impact of dynamic changes in fracture width to establish a heterogeneous fracture network apparent permeability model. The results show that： （1） The surface diffusion of small-scale fracture network can be ignored when the formation pressure is greater than 10 MPa， the proportion of viscous flow is proportional to the formation pressure， and Knudsen diffusion is the opposite. （2） The Knudsen diffusion of large-scale fracture network increases with the increase of formation pressure， first increases and then decreases. Surface diffusion and viscous flow show a trend of decreasing and increasing， respectively. The permeability of small-scale fracture network first decreases with the increase of formation pressure and then increases. The permeability of the large-scale fracture network is proportional to the formation pressure. （3） The minimum fracture width（b_min=10^-7 m） is a constant. The maximum fracture width is increased by 10 times， the permeability of the fracture network is increased by 100 times， and the permeability of the fracture network is proportional to the fracture width. （4） The maximum fracture width （b_max=10^-4 m） is constant， and the permeability of the small-scale fracture network is slightly larger than that of the large-scale at low pressure （5 MPa）. The minimum fracture width has little effect on the permeability； The fracture porosity increases， and the denser the fracture network， the higher the permeability； （5）The research results of this paper have guiding significance for the study of the seepage characteristics of fracture network stimulated area and the seepage mechanism under different pressures and fracture network scales.

As a demonstration zone for commercial shale gas development in my country， the areas in southern Sichuan Basin have a good prospect for exploration and development. In order to solve the problem of large different single well productivity in shale gas and low energy and low efficiency of some production wells， starting from the actual gas production effect of the X block， combined with shale logging interpretation data， X-ray diffraction， rock organic carbon analysis and reservoir physical properties， the factors which influence shale gas production were analyzed to determine the evaluation index of the geological selection of the shale gas industrial production area， also using 8.0×10⁴ m³/d as shale gas industrial flow lowest limit， exploring the lowest limit standard of corresponding evaluation index. The study shows that： （1） The drilling rate of high-quality reservoir， TOC content， porosity， and brittleness index have a significant effect on shale gas production capacity， and these can be used as a key indicator for the selection of shale gas industrial production areas. （2） Shale gas production capacity is not necessarily related to the total gas content of shale， but it has a very obvious positive correlation with the relationship between free gas content and free gas proportion. Therefore， free gas content and proportion of shale can be used as one of the evaluation indicators for the selection of production areas. （3） Compared with BI_mer and BRMC4， BI_bm can better indicate the shale brittleness. （4） To reach the lowest limit of industrial oil and gas flow， it is recommended that the drilling rate of high-quality reservoirs should reach at least 65%， TOC content should reach 3.3%， porosity should reach 3.5%， gas content should reach 3.0 m³/t， and the ratio of free gas accounts should reach more than 60%，that is，the free gas content should reach 2.0 m³/t， and the BIbm should reach 0.5.

Shale oil in Chang 7 member （Abbr. as Chang 7） mainly developed as gravity flow deposits in semi-deep to deep lacustrine environment. Compared to the marine shale rocks in North America， continental shale oil in Chang 7 is thin in single sand body， poor in lateral continuity， strong in reservoir heterogeneity， tight in its reservoir and low in formation pressure index. These characteristics made it more difficult to develop shale oil in Chang 7 and thus shale oil has driven much attention as it might be another significant superseding area for national energy safety in China. After years of research and field practice， “volume development” theory was proposed based on the unique characteristics of the shale oil in China. Guided by the theory， complex artificial fracture systems are established after multi-section fracturing in horizontal wells， and thus forms a composite flow pattern including nonlinear seepage and imbibition replacement processes between multi-sized artificial fractures and the matrix. Application of the theory has dramatically optimized the seepage environment and created “artificial oil and gas reservoir” underground， and thus established a key technology characterized with long horizontal well， short well spacing， large well cluster， stereoscopic fracture and subdivision volumetric fracturing. This technology has made commercial development of shale oil in Chang 7 possible and a demonstration area with one-million tons of annual shale oil production has been established. It also provides theoretical basis and technical support for an overall development of the continental shale oil in China.

With the comprehensive development of Fuling shale gas field， the analysis of production dynamics， production characteristics and development evaluation of shale gas wells has become an urgent problem to be solved. In the view of the production dynamics of conventional and unconventional shale gas reservoirs， scholars have proposed different classical decline curve analysis methods for evaluation. These methods， from empirical to semi-empirical and theoretical， all have assumptions and limitations， all have certain assumptions and limitations， and are not universal. By using the law of decline found in actual production data， a new model of decline calculation is established， and the analytical results are compared with the classical model. The research results show that： （1） The relationship between the monthly decline rate of 60， 120 and 180 days calculated from the actual production data and the production time is well fitted with the power law exponential model， which indicates that the decline rate at the stage of gas well production decline presents a power law decline； （2） On the basis of establishing the model of the decline rate by using the power law exponential model， the constant decline rate is changed into variable decline rate by optimizing the differential calculation method， and a new simplified decline curve model is proposed； （3） Compared with the existing Arps harmonic decline model， Hsieh decline model， PLE decline model and Duong decline model， the new calculation model shows better fitting effect， with relative error within 2%-4%.

The Sinian Dengying Formation gas reservoir in Sichuan Basin is an ancient， deep， low-porosity and strongly heterogeneous karst carbonate gas reservoir. Due to the limitation of the existing industry standards on reservoir types， the response of dynamic and static data can not be one-to-one correspondence. Therefore， based on the static data， the reservoir of Sinian Dengying Formation gas reservoir in Sichuan Basin was subdivided into two stages from the perspective of development， the dynamic response of various reservoirs were clarified， and the technical countermeasures for gas wells in different production stages of different types of reservoirs are formulated. The technical countermeasures include：（1） The production organization strategies for five types of reservoirs are defined，i.e. the strategy of high production and high pressure should be implemented for fractured-vuggy I and porous-vuggy I，the ratio of porous-vuggy I is optimized to 1/4-1/3；the strategy of low production and low pressure should be implemented for fractured-vuggy II，porous-vuggy II and pore I，the ratio of fractured-vuggy II is optimized to 1/12-1/10. According to this strategy， the gas wells with established reservoir type should be optimized and the production flow sections should be divided and the early dynamic reserve evaluation should be carried out. （2） For those that have been put into production but the reservoir type is not clear， it is necessary to evaluate whether the production of gas wells is stable，preliminarily determine the reservoir type，carry out dynamic monitoring， implement reservoir subdivision types， and optimize gas well production allocation according to countermeasures （1）. （3） For production building wells， they should be divided into different types according to static data after oil testing， and production allocation should be designed according to the scheme after production. Dynamic data should be accurately enrolled to prepare for the determination of reservoir types. The research results provide an effective support for the upper production of Dengying Formation gas reservoir and the long-term stable production of 60×10⁸ m³/a scale.

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.