Abstract:The tight sandstone gas resources of the 2nd Member of Xujiahe Formation in Xinchang area of the western Sichuan Depression have great potential，but the fine description of the range of fault-fracture bodies is a technical difficulty that restricts exploration and development. On the basis of seismic，core，and imaging logging data as well as seismic attribute technology，seismic predictions were made for the fault-fracture bodies in the 2nd Member of Xujiahe Formation in Xinchang area，and the geological development modes of fault-fracture bodies were summarized. The results show that the faults in this member are undeveloped and are mainly anticlines，with an overall NE/NNE trend，and the third-and fourthorder faults are developed in the east，mainly in NE，near EW，and near SN trends. The fractures found in this member are controlled by the third-and fourth-order faults. With an EW trend，the fractures are dominated by flat fractures（<10°）and low-angle fractures（10°-30°）and are most widely developed in the upper sub-member sand group T3x2-2 and the middle sub-member sand group T3x2-4. The fractures can be divided into fault-related and fold-related fractures：For fault-related fractures，the seismic attribute of thin likelihood can objectively describe the fault slip surface，and the seismic attribute of chaos can depict the fault fractured zone and induced fracture zone；for fold-related fractures，the seismic attribute of curvedness can describe the development area of fold-related fractures.Furthermore. The fault-fracture bodies in the 2nd Member of Xujiahe Formation can be classified into fault-fracture bodies，fault-fold-fracture bodies，and fold-fracture bodies，among which the fault-fracture and fault-fold-fracture bodies are the most widespread and are mainly distributed near the faults in the east，while fold-fracture bodies are developed locally，usually with a small distribution range.

Abstract:The Middle Permian Pingdiquan Formation in the piedmont depression of Kelameili Mountain in eastern Junggar Basin is equivalent to Lucaogou Formation and Hongyanchi Formation in the piedmont depression of Bogda Mountain. Lucaogou Formation and Pingdiquan Formation are important series of strata with source rocks. The isochronous stratigraphic framework of Lucaogou Formation and Pingdiquan Formation has not been established，which affects the distribution range of source rocks in horizontal and vertical directions. According to the systematic analysis of well seismic，outcrop and geochemical data，this paper divides the sequence stratigraphic units of Lucaogou Formation and clarifies the corresponding relationships with Pingdiquan Formation. Moreover，the paper establishes the sedimentary filling models of Lucaogou Formation in eastern Junggar Basin. The results show that the middle Permian Lucaogou Formation and Hongyanchi Formation on the periphery of Bogda Mountain are both third-order sequences，respectively corresponding to the third-order sequence1 at the lower part of Pingdiquan Formation and the third-order sequence 2 at the upper part.Lucaogou Formation（Sequence1）develops lowstand，transgressive and highstand system tracts. The lowstand system tract is dominated by fan delta，delta and shore-shallow lake deposits，and the semi-deep lake-deep lake facies is only distributed in Bogda area. The distribution ranges of semi-deep lake-deep lake facies in the transgressive system tract reach the maximum in each sag.The scales of fan delta，delta and turbidite fan sand bodies in the highstand system tract increase，and the distribution ranges of semi-deep lake-deep lake facies decreases. During the sedimentary period of transgressive and highstand system tracts in Lucaogou Formation，the semi-deep lake-deep lake facies developed high-quality source rocks，which formed a good source-reservoir assemblage with various types of sand bodies in the highstand system tract. The highstand system tract of Lucaogou Formation is favorable exploration strata of Middle Permian in eastern Junggar Basin.

Abstract:Zigong area of Sichuan Basin is the main battlefield of shale gas exploration in the Lower Silurian Longmaxi Formation. The test results of the first batch of horizontal wells deployed in this area are not ideal，and the average test production of a single well is only 7.6×104 m3/d. The test production of the latest batch of horizontal wells has been greatly improved by employing geology-engineering integration，conducting a comprehensive evaluation of target layers，and pointedly adjusting the target position. The following are the main research ideas for the quantitative evaluation and target adjustment of the high-silica shale sections of Longmaxi Formation in Zigong area. Firstly，the“sweet spot”layers are evaluated on the basis of geology-engineering integration，and Long11 sublayer is confirmed to be the best“sweet spot”layer for horizontal well deployment. Secondly，according to the classification standard of a high-silica shale section，Long11 sublayer is innovatively divided into an upper section，a medium section，and a lower section vertically. Fine reservoir evaluation is conducted mainly on the high-silica shale sections. It is clarified that the high-silica sections，with obvious advantages in gas-bearing property，brittleness，fracturing ability，etc.，can be used as the optimal target position. Thirdly，the single-well daily gas production after target adjustment is 20.01×104 m3/d，which is 2.6 times the value before target adjustment（7.64×104 m3/d）. This result fully demonstrates that the carbon-rich and high-silica shale sections are the optimal solutions of target adjustment in this area. With the target adjustment direction of horizontal wells as the thread，this paper systematically expounds the reservoir conditions of the high-silica shale sections in the middle-low Long11 sublayer and increases the gas production by lowering the target position.

Abstract:This study is conducted to explore the influence of the evolution of shale reservoirs on their fractal dimensions.Specifically，three examples are selected for the case study，namely，the terrestrial shale with low maturity of Yanchang Formation in Erdos Basin，the terrestrial shale with high maturity of Shahezi Formation in Songliao Basin，and the marine shale with high and excessive maturity of Longmaxi Formation in the southern Sichuan region. On this basis，the evolution characteristics of different fractal dimensions are studied by means including X-ray diffraction（XRD），geochemical analysis，and nitrogen adsorption experiments in combination with the Frenkel-Halsey-Hil（FHH）and thermodynamic models. Moreover，the grey relational analysis（GRA）was performed to analyze the controlling factors of fractal dimensions in different evolution phases. The results reveal that the terrestrial shale with low maturity has low fractal dimensions，whereas the terrestrial and marine shale with high maturity has high dimensions. In the marine shale evolved from high maturity to excessive maturity，a high pore volume and surface area have a significantly positive relationship with the pore complexity，but this relationship is not prominent in the terrestrial shale with low maturity. The reason might be that the occluded hydrocarbon causes micropore blocking or covers the surface of pores，which reduces the fractal dimensions. As the evolution increases，the main influencing factor of the fractal dimensions of shale reservoirs gradually changes from the mineral compositions to the total organic carbon（TOC）.

Abstract:At present, there is still a lack of research on how to use the discovered conventional oil and gas reservoirs to predict undiscovered unconventional oil and gas reservoirs. In light of the positive accumulation correlation between conventional oil and gas reservoirs and unconventional ones in the source rock strata, this paper proposes a method for the favorable area prediction of unconventional oil and gas reservoirs in the correlated reservoir ranges based on reseach of the saguplift band distribution, fault activities, sand body distribution, oil and gas sources, and migration paths. First, the basic research on the correlation is conducted for an area in terms of the stratum structures in the sag-uplift band, sand body distribution in the source rock strata, oil and gas sources, and migration paths. Then, the distribution of discovered oil and gas reservoirs and their oil and gas sources are combined with the basic research results to comprehensively judge the correlation range. Finally, the favorable areas are predicted in the regions where no oil reservoirs are found in the correlation ranges. Here, the favorable areas are defined as those with the source rock development and favorable sandstones, sand-mud interbeds, and fractured mud-shale reservoirs. The following two conditions are the most favorable for oil and gas accumulations: there are the source rock strata oil and gas reservoirs superimposed or adjacent to each other in favorable areas；the favorable areas are adjacent to the faults，and the oil and gas reservoirs developed in the overburden strata with oil and gas derived from faults.

Abstract:Hangzhou slope belt is an important new oil and gas exploration area in the northern part of the western slope belt in Xihu Sag. Nevertheless，its basic geological characteristics，especially its sedimentary characteristics，are not clear yet. For this reason，well logging，seismic，trace elements，and paleontological data were examined to study the sedimentary environment of Pinghu Formation of Hangzhou slope belt in Xihu Sag. The corresponding relationships of sedimentary facies with seismic facies were constructed and the planar distribution characteristics and vertical evolution law of the sedimentary system were summarized after the sedimentary features are discussed. The following observations could be made from the results：Pinghu Formation in the study area has a semi-enclosed bay environment in general，where the delta and barrier coast sedimentary systems mainly develop. The delta sediments mainly develop on the western edge of Hangzhou slope belt while the barrier coast ones widely distribute. Pinghu Formation has undergone a complete transgression-regression process. The deltas distributed continuously during the sedimentation of the Fifth Member of Pinghu Formation. Then，the deltas were inherited and the tidal flat scale was the largest during the sedimentation of the fourth Member of Pinghu Formation，which was the marine transgression. The deltas slowly expanded toward the center of the sag during the sedimentation of the Third Member of Pinghu Formation. The sea level dropped and the inherited deltas kept advancing on the western edge of Hangzhou slope belt during the sedimentation of the Second Member and the First Member of Pinghu Formation which were the marine regressions.

Abstract:Yanchang Oilfield has rich reserves of low permeability reservoirs，but the conventional waterflooding development of these reservoirs shows the poor performance and the low oil recovery due to the tight reservoir matrix and the complex fracture systems. Therefore，it is urgent to enhance oil recovery in Yanchang Oilfield. In this paper，a new theory of “corrosion increasing permeability，wetting promoting permeability”was proposed for CO2 immiscible flooding in low permeability reservoirs base on the technologies and the field practices of the integrated CO2 immiscible flooding and sequestration，the air foam flooding at low temperature，the bioactive combination flooding and the microbial flooding. A CO2 immiscible flooding technology was developed to mainly improve CO2 miscibility and enhance 3D equilibrium producing of CO2 flooding. Moreover，the complex oxygen consumption mechanism in shallow reservoirs with a low temperature was revealed，and the formula systems of the air foam，the bioactive agents，and the endogenous microbial activators were improved. The field practices indicated that the prospect of enhanced oil recovery technology for low permeability oil reservoirs is broad in Yanchang Oilfield.

Abstract:As most of the heavy oil reservoirs in Shengli Oilfield enter the development stage of medium and high water cut，it is imperative to change the development mode. Microbial enhanced oil recovery（MEOR）technology can specifically tackle the difficulties in the exploitation of hard-to-recover heavy oil reservoirs，such as multiple rounds of thermal recovery，low efficiency of water flooding，deep heavy oil，and sensitive heavy oil reservoirs，through the in-situ action on crude oils and reservoirs by microorganisms and their growth and metabolism. In the past five years，research was conducted on the MEOR technology for hard-to-recover heavy oil reservoirs in Shengli Oilfield，and major mechanisms of MEOR were revealed，including degradation of heavy components by hydrocarbon-philic emulsifying microorganisms to reduce oil viscosity，viscosity increase by biopolysaccharides to regulate oil displacement，biogas production assisted oil displacement，interface modification to reduce flow resistance of oil，and swelling prevention by modified minerals. On this basis，four key technologies were developed，i.e.，quantitative gene analysis of microbial community in heavy oil reservoirs，high-efficiency activation of in-situ hydrocarbon-philic microorganisms for oil displacement，prediction of production performance with microbial characteristics，and changing biological field by injection-production regulation. The research results were applied on site in 15 low-efficiency heavy oil reservoir blocks in Shengli Oilfield，all of which were highly effective in oil production increase and water cut reduction，with enhanced oil recovery（EOR）more than 3%. The successful promotion of MEOR technology in hard-to-recover heavy oil reservoirs confirms its huge application potential in the conversion and development of heavy oil reservoirs. It is a revolutionary technology for the conversion and development of mature oilfields，quality improvement，and efficiency enhancement，showing broad promotion prospects.

Abstract:Microbial oil recovery mechanisms include hydrocarbonophilic viscosity reduction，emulsification，wettability alteration，and gas production. In the microbial wettability mechanism，microorganisms and metabolites modify the reservoir interface to improve oil displacement efficiency and crude oil percolation capacity. The current research progress in the role and micro-mechanism of microorganisms and metabolites in wettability modification was summarized，and the problems and development directions of microbial oil recovery technology，which require in-depth research for wettability modification，were presented. Current studies have confirmed that the microbial cells and metabolites can change the wettability of the rock surface to varying degrees，and the reasons for this phenomenon may be as follows：①The biological surfactant produced by microbial metabolism is adsorbed on the rock surface through the cleaning or covering mechanism，thereby changing the wettability of the rock surface. ②Microbial cells grow and multiply on the oil-water or oil-solid interface to form a viscoelastic biofilm，thereby completing wettability alteration. Due to the complex multi-mechanism synergistic reaction of the microbial oil recovery mechanism，the contribution of the biological wettability mechanism to enhanced oil recovery and the adaptability of oil reservoirs have not yet been clarified. Therefore，it is necessary to deepen the research on the wettability mechanism of microorganisms and metabolites and clarify its scope of action，stability，and reservoir adaptability to provide theoretical support for improving the field application of microbial oil recovery.

Abstract:With the development of unconventional oil and gas resources，secondary and tertiary oil recovery technologies for enhanced oil recovery in unconventional reservoirs have attracted widespread attention from scholars. Foam flooding has achieved good results in the development of medium and high water-cut oil reservoirs due to its unique properties of plugging water instead of oil，and foam stability is a key factor affecting the effect of enhanced oil recovery. In recent years，technologies such as polymer-enhanced foam and nano-particle foam stabilization have become the research focuses for scholars both in China and abroad. However，these enhanced foam technologies still have problems such as large foam diameters，great difficulty in removing adhesive polymers in reservoirs，and high technical costs，which limit the promotion and use of these technologies in low-permeability reservoirs. Compared with ordinary foams，micro-foams have the characteristics of small diameters（10-100 μm），large specific surface areas，high stability，and water-like fluidity. As a potential tertiary oil recovery technology，micro-foam flooding has the advantages of low injection pressure and wider coverage. Moreover，its injection pressure is only a third of the injection pressure of the ordinary foams，at the same time，it can effectively control its gas fluidity，expand the swept volume，and enhance oil recovery. On the basis of literature research，this paper introduced the structure and properties of micro-foams and the principle of micro-foam plugging and enhanced oil recovery，and the current research status of the micro-foam flooding technology for enhanced oil recovery is summarized. Finally，this paper indicated the problems of micro-foams in the development of low-permeability reservoirs and forecasted the development potential of micro-foams in the application of enhanced oil recovery.

Abstract:As important strategic replacement resources in China，shale oil and gas are the main force for increasing oil and gas reserves and production in the future. However，given the development of micro/nano-scale pores in shale matrixes，reservoir stimulation is required for its flow capacity improvement，so as to achieve efficient development of shale reservoirs.Heat treatment technology，which is green and environmentally friendly，is a new approach to reservoir stimulation and recovery enhancement. It is capable of improving the physical properties of shale by generating heat energy in formations，thereby enhancing the seepage capacity of reservoirs. Therefore，it is of great significance for reservoir stimulation to accurately understand the shale reservoir stimulation mechanism and grasp the change laws of physical properties of shale in a thermal environment. With the help of the characteristics of shale oil and gas reservoirs，the shale reservoir stimulation mechanism under heat treatment was analyzed after the research results regarding pore structure changes in shale during heat treatment was investigated in China and abroad. The results show that the non-uniform thermal expansion of rocks and minerals produces thermal stress，which leads to thermal expansion of fractures. The pyrolysis of organic matter gives rise to the development of organic pores，and the pressurization due to the evaporation of pore fluids and the water-rock interaction both promote the increase in pore space of rocks. Through the above mechanism，the internal storage space of reservoirs is increased and the conductivity is enhanced，as a result of which the effective exploitation of shale oil and gas can be realized. Besides，this paper summarizes the change laws of physical and mechanical properties of shale under thermal stress. Specifically，the porosity and permeability of shale increase significantly at high temperatures. Under the condition，the average pore diameter inside the shale increases，and a large number of micro-fractures develop to form a complex fracture network. The overall strength of shale is reduced and the plasticity is enhanced，which facilitates hydraulic fracturing，heat treatment and other measures to increase production.

Abstract:The matrix permeability of shale oil reservoirs is extremely low，and gas huff-n-puff is an effective technology for enhanced oil recovery（EOR）of shale oil. Due to artificial and natural fractures，field tests showed that gas channeling from adjacent wells was serious during huff-n-puff gas injection. Injecting foam can reduce gas fluidity，increase the swept volume of huff-n-puff，and inhibit the gas channeling between fractures. Four foaming agents were screened through laboratory experiments. The foaming ability and foam stabilization were evaluated to select the foaming agent with the best comprehensive performance，and then the gas channeling law during huff-n-puff gas injection in the fractured shale core was explored. In addition，the plugging performance in the fractured core after foam injection was studied，and the potential of foam channeling control for EOR by huff-n-puff gas injection in shale cores was explored. The results demonstrate the AOS foaming agent with a mass fraction of 0.4% shows the optimal stability；the pressure difference of foamed gas plugging generated after the simultaneous injection of gas and liquid grows to 6.67 MPa，and the gas breakthrough time increases by 13.72 times；based on foam plugging，five cycles of huff-n-puff can enhance the total recovery factor by 6.58%.

Abstract:Low-permeability conglomerate reservoirs are characterized by strong heterogeneity，small pore throat radius，and complex mineral components. In water injection development of the reservoirs，the content and particle size of suspended solids in reinjection water are main factors leading to reservoir damage. However，the recommended indicators of injection water quality for low-permeability clastic reservoirs are unsuitable for conglomerate reservoirs. Therefore，injection water quality indicators for low-permeability conglomerate reservoirs should be formulated based on the characteristics of the reservoirs. According to the pore structure and clay mineral properties of low-permeability conglomerate reservoirs，this paper employed CT scanning，scanning electron microscopy，and X-ray diffraction to analyze the main factors causing potential damage in water injection from a multitude of perspectives. Additionally，according to the particle plugging theory，suspended solids（SS）in injection water will block the pore throat channel during the injection，resulting in a decrease in permeability and serious damage to low-permeability conglomerate cores. The experimental results show that there are large differences in the damage incurred by concentrations and median particle sizes of SS to the conglomerate cores. To achieve the goal of damage to the target reservoir less than 20%，SS concentration have to be ≤ 1.43 mg/L and median particle size ≤1.9 μm in the reservoir when the permeability is ≤ 9.28 mD；SS concentration ≤ 3.1 mg/L and median particle size ≤ 2.6μm in the reservoir when the permeability is in the range of 9.28-46.9 mD；SS concentration ≤ 5.1 mg/L and median particle size ≤ 4.8 μm in the reservoir when the permeability is ≥ 117 mD.

Abstract:The gas-water relative permeability curve is an important basic parameter to describe the gas-water flow law of water-producing gas reservoirs. However，it is still controversial to determine the gas-water relative permeability curve by the water-drive-gas method or the gas-drive-water method. Taking reservoirs in Yuanba gas field as the research objects，the systematic laboratory experiments were conducted to study the gas-water relative permeability curves of porous and fractured cores. The gas-water relative permeability curves of cores from different types of reservoirs were compared and analyzed，and the test method was recommended for the gas-water relative permeability curves in water-producing gas reservoirs. The results demonstrate that the gas-water relative permeability curves of fractured cores are concave，which are quite different from conventional X-shaped curves；compared with that of fractured cores，the gas-water relative permeability curves of pored cores move to the right as a whole；the ranges of two-phase flow saturation are wider，and the waterphase relative permeability rises more slowly. Compared with that by the gas-drive-water method，the irreducible water saturations from the permeability curves by the water-drive-gas method are closer to the actual situation of the reservoir；the water phase flow capacity is weak，while the gas phase flow capacity is greater than that of the water phase. The experimental design is in line with the gas-water flow process in water-producing gas reservoirs. Therefore，for the productivity evaluation and development plan design for water-producing gas reservoirs，it is recommended to use the gas-water relative permeability curve tested by the water-drive-gas method for numerical simulation.

Abstract:The adjustment of well patterns is often encountered during the development of oil fields. The inverted nine-spot pattern is adopted in the initial development stage of x oil reservoir. During its production，high-water-cut oil-producing wells are converted into injection wells，and production wells are infilled between rows，which means the well pattern is changed into a row injection-production well pattern. After the adjustment of well patterns，the flow field between injection and production wells will change，and the flow laws of fluid will become complicated. To study the evolution characteristics of the flow field from the inverted nine-spot pattern to the row injection-production well pattern，this paper considered the heterogeneity and compaction of reservoirs for solving the potential function equation and obtained the streamline of the inverted nine-spot pattern. On the basis of the actual adjustment mode of well patterns，the streamline model for the change from the inverted nine-spot pattern to the row injection-production well pattern was derived，and the streamline after well pattern adjustment was obtained. The results reveal that the streamline partition area of the inverted nine-spot pattern is in the main flow area of the row injection-production well pattern，and upon infilling，the streamline between injection and infill wells passes through this area. Therefore，the water flooding control degree of the pattern is improved，and the area with poor displacement effect is affected by the injected water. The immovable area of the row injection-production well pattern is in the mainstream area of the inverted nine-spot pattern，which has been displaced by injected water during the development of the inverted nine-spot pattern. The streamline distribution characteristics demonstrate that the water flooding effect is poor in the streamline partition area between edge and corner wells of the inverted nine-spot pattern，the streamline partition area between the row production wells of the original production well and the infill wells in the row injection-production well pattern，and the superposition area of the streamline partition area before and after infilling. The study reveals the evolution characteristics of the flow field from the inverted nine-spot pattern to the row injection-production well pattern，which provides a theoretical basis for the secondary infilling adjustment of well patterns.

Abstract:According to the distribution characteristics of remaining oil in high water cut oilfields，the pre-making method of fitting samples of oil saturation isolines and the remaining oil prediction method based on the artificial neural network are proposed. This paper applies the numerical simulation method to generate the remaining oil distribution fields between injection and production well groups under different well spacings，physical properties，working systems，and other conditions in batches. It programs a module to automatically extract a small amount of oil saturation isolines and constructs fitting parameter sample data set by polynomial functions to fit the oil saturation isolines at different times and horizon. This method can reduce the sample parameters of machine learning. Tensorflow is adopted to construct the neural network model. After the learning and training process，the oil saturation isoline prediction model between injection and production well groups is formed. The oil saturation field is reconstructed according to the superposition results of isoline maps between multiple well groups. Comparison between the actual data of high water cut oilfield and numerical simulation shows that the new method has prediction ability for fault boundary，interlayer residual oil enrichment area，and local scattered remaining oil between wells. This method can quickly convert dynamic data of oil and water wells into saturation field data. Compared with the traditional method，the proposed method significantly improves the calculation speed and quantification.

Abstract:To reveal the mechanism of injection increase and deepen the understanding of the initiation and propagation mechanism of fractures in fracturing flooding，we studied the influencing factors of breakdown pressure with the physical simulation test of fracturing-flooding. The experimental results show that the breakdown pressure of rock samples rises with the increase in the injection rate，decreases exponentially with the increase in rock permeability，and grows linearly with the rise in confining pressure. On the basis of micro-CT scans，the characteristics of fracture distribution in fracturingflooding were analyzed on a micron scale.The results show that in the process of fracturing-flooding，vertical fractures are formed along the radial direction and distributed in a plane，and on a micron scale，the fracture propagation path winds along the grain boundary.Combined with the physical simulation test of fracturing-flooding and the micro-CT scans，the porosity，pore diameter，and fracture aperture were introduced as pore structure parameters，and a method suitable for physical simulation of fracturing-flooding and quantitative characterization of fractures on a micron scale in low-permeability reservoirs was established. This method can accurately characterize the breakdown pressure of fracturing-flooding and the width and morphological characteristics of fractures on a micron scale.

Abstract:Fracture-cavity carbonate reservoirs have strong heterogeneity and complex fluid distribution. It is often difficult to obtain parameters related to productivity prediction by conventional methods，which brings a great challenge for accurately predicting the single well productivity. This paper proposes a new method for predicting the single well productivity by selecting optimized common seismic parameters. After establishing a matrix-fracture-cave triple medium model，this paper optimizes seismic parameters affecting the single well productivity by Spearman and Pearson method，establishes the relationships between the optimized seismic parameters and the interporosity flow coefficient and storativity ratio，and introduces it into the triple medium productivity equation to predict the single well productivity of the reservoirs with different geological conditions. Based on the actual production data and preliminary test data of a fracture-cavity carbonate reservoir in Xinjiang，this paper uses the new method to predict the productivity of 134 oil wells in four areas（fault areas，underground river areas，aground river areas，and composite karst areas）and analyze errors. The results show that this method has the highest accuracy in predicting the productivity of oil wells in underground river areas，up to 87%，and for oil wells in aground river areas and composite karst areas，the prediction accuracy is low and is about 80%. The average prediction accuracy of this method is 83%，which is higher than those of multiple linear regression，BP neural network，and support vector machine. The new method makes full use of the existing seismic data，further improves the productivity prediction accuracy，and provides a new idea for predicting the productivity of complex fracture-cavity carbonate reservoirs.