Oil & gas exploration and development is a combination of innovative thinking and practice. Firstly, a geologist should have the concept of oil and gas in his mind. The geologists should constantly emancipate their minds and be full of passion for oil exploration. They should look at the problems in a sight of development, re-recognize themselves, re-recognize the underground, re-recognize the potential of geological-engineering integration, and study the geological situation of oil and gas reservoirs with the continuous development of the understanding. On the basis of re-understanding the exploration discovery of Well-Yan1, the theory of fault-fracture body reservoir is formed by summarizing the exploration and development practice and the field geological investigation of oil and gas reservoirs in Ordos Basin. The continuous innovation of exploration and development theory has realized the continuous breakthrough of exploration and development in Ordos Basin. As the annual oil and gas equivalent has exceeded 80 million tons, Ordos Basin become the first oil and gas bearing basin in China. By summarizing the experiences of Sinopec North China Oil and Gas Company in oil and gas exploration and development in Ordos Basin, it is found that seeking truth from facts is the key to deepen the understanding of oil reservoirs for the breakthrough of oil and gas exploration, the philosophical method of dialectical thinking can obtain new understanding of oil and gas geology at different stages, the fine description of oil and gas reservoirs is the basis for the preparation of development plans, and the integration of geological engineering realize the benefit development of tight oil and gas reservoirs. The object of oil and gas exploration and development will be more complex in Ordos Basin. As a result, the oil and gas exploration should focus on the whole basin to re-recognize the oil and gas reservoirs, and find different types of oil and gas reservoirs by the breakthrough of exploration and development theory.

In order to solve the problems of the difference in macro-heterogeneity between the southern and northern sandstone reservoirs in the southern and northern He-1 Member of Hangjinqi, Ordos Basin, and the unclear relationship with gas reservoir types, the He-1 sandstone reservoir is taken as the research object and its identification criteria for reservoirs and compartments are defined by sandstone classification. Then, the sand body combination style is establish. And according to the development characteristics of the reservoir in the study area, the ratio of reservoir thickness to formation thickness, the ratio of reservoir thickness to formation thickness, the number of barriers, and the frequency and density of barriers are selected to characterize the characteristics of macro-heterogeneity of He-1 Member. The relation between the macro-heterogeneity and gas reservoir types is discussed. The researches are conducted as follows. ①The sandstone of the He-1 Member is divided into three types. The properties of the microfacies of box-shaped core beach in the type Ⅰ reservoir is better than that of the filling facies of the toothed box channel in the type Ⅱ reservoir. ②Three sand body assemblage modes of the He-1 Member are established. The southern part is dominated by the assemblage modes of type Ⅰ and type Ⅱ sandbody, and the northern part is dominated by the assemblage modes of type Ⅲ sandbody. ③The macro-heterogeneity of the reservoir in He-1 Member is strong in the south part and weak in the north part. ④Lithological gas reservoirs are developed in the south part with the ratio of reservoir thickness to formation thickness of less than 0.3. While the ratio of reservoir thickness to formation thickness of the north-east part is greater than 0.3 with good reservoir connectivity, which is mainly used as a natural gas migration channel and conducive to the formation of structural gas reservoirs and structural-lithological composite gas reservoirs. The gas-bearing capacity of type Ⅰ reservoirs in the south is better than that in the north. The conclusion is that the macro-heterogeneity of the reservoir of He-1 Member is strong in the south part and weak in the north-east part; the macro-heterogeneity of the reservoir affects the type of gas reservoirs, making the south part to be a lithologic gas reservoir area, and the north-east part to be a structure-lithological complex gas reservoir area. Type Ⅰ reservoirs with a ratio of reservoir thickness to formation thickness of less than 0.3 in the south part are the favorable target areas for well location deployment. It points out the direction for the selection of exploration area in He-1 gas reservoir.

The average porosity and permeability of sandstone of Lower Shihezi Formation of Permian system in Shilijiahan area of Hangjinqi area are of 8.3 % and 0.89×10^-3 μm² respectively, causing the reservior to be a typical tight sandstone reservoir. Meanwhile, the microfractures play an important role in improving the physical properties of tight sandstone reservoir. Therefore, the researches of the reservoir in this area focus on the microfractures. By the observation of the microscopic thin section, and combined with the mercury injection, core physical properties and structural characteristics, the types and genesis, formation stages, control factors and the influence of micro fractures on physical properties in this area have been studied. The results show that the tight sandstone of Lower Shihezi Formation in the study area can be divided into intragranular fracture, grain edge fracture and grain penetrating fracture according to the contact relationship of strata, and can be divided into unfilled fracture, incomplete filled fracture and complete filled fracture according to the filling degree. According to the genetic analysis, there are at least three stages of micro fractures in the study area. Their development degree are controlled by the combination of internal factors （sandstone particle size, rock debris composition, rock debris and interstitial content, contact relationship between particles, etc.） and external factors （tectonic stress）. The microfractures mainly affect the permeability of the reservoir. The multi-factor influence is a basic feature of micro fractured tight reservoir. The average throat radius plays a major role in controlling the permeability of the reservoir.

Taking He2+3 Member in shiguhao gas area of Dongsheng gas field as the research object, the types and plane distribution of sedimentary facies in this area have been described, and the relation between sedimentary microfacies and natural gas distribution has been studied. Due to the influence of complex paleogeomorphic characteristics on the sedimentary system distribution, the transportation channel of sedimentary debris and the distribution space of sedimentary system mainly is defined by the description of paleogeomorphology. On the basis of core observation, 14 lithofacies types and 5 lithofacies associations are summarized, and three sedimentary microfacies of channel bar, braided channel and river flood deposition are identified in He2+3 Member. The vertical sedimentary sequence of typical wells is analyzed, which is dominated by the normal grain sequence with coarse grain size, forming a single-stage large set of thick gravelly medium-coarse sandstone. The vertical and plane distribution characteristics of braided river sedimentary facies are characterized. The sand body is distributed in a nearly north-south strip, and the river channel migrates and swings frequently laterally. Combined with the reservoir physical parameters, the influence of different microfacies on reservoir physical properties is summarized, the distribution of gas-bearing reservoirs in sedimentary microfacies is analyzed, and finally the braided river channel bar is proved to have good physical properties and gas-bearing properties, which has great natural gas development potential.

The Xujiahe Formation in Xinchang area of western Sichuan Depression has experienced multiple periods of tectonic movement superposition. The stratigraphic deformation is significant, and the whole stratum is characterized by “saddle” shape. In addition, several groups of reverse faults are developed, with different fault broken horizons and diverse fault crosscutting relationships. However, the conventional modeling methods can not accurately describe the complex structure-stratigraphic characteristics of the area, and the model is difficult to meet the actual production needs. Therefore, the VBM modeling method is used to establish the structural-stratigraphic framework model of Xu2 gas reservoir in Xinchang area. Based on the analysis of sedimentary and filling characteristics in the study area, the sequence stratigraphic framework is clarified. Then, the horizon and fault data are obtained based on seismic interpretation data and drilling stratification information to establish the model of fault frame and finely adjust the relation between sectional shape and cross section. The horizon model is used as the input data to calculate the stratigraphic thickness of each sand group, and to restore and construct the original formation model. The present structural-stratigraphic framework model can be established by accurately regulating the relation between faults and horizons by controlling the relevant parameters of them. The results show that VBM method can accurately describe complex structural model through volume conservation principle and tetrahedron grid characterization technology, and better deal with complex formation contact and fault distribution problems. The new stratigraphic framework model has higher grid quality than the traditional corner grid model, and the combination relation and sequence stratigraphic characteristics are maintained in the complex faults. This structural-stratigraphic model provides a more reliable model framework for the subsequent reservoir geological modeling.

The tight sandstone reservoirs in Xujiahe Formation in Sichuan are rich in oil and gas, but highly heterogeneous. The tight sandstone fractured reservoirs of Xujiahe Formation in Western Sichuan Depression are characterized by heterogeneity. Combining with the actual situation and based on rock physics analysis, the relationship between reservoir characteristic parameters and anisotropy parameters is deduced, and the anisotropic elastic impedance inversion workflow of tight sandstone reservoirs is carried out. Based on the proposed fracture parameter inversion method, the model and the actual work field data are tested, respectively. The results show that the proposed approach has great robustness, the inversion results are in good agreement with the well-log, and the estimated anisotropy parameters can accurately show the location of fractured reservoirs and achieve effective description of the fracture characteristics of tight sandstone reservoirs.

The pore throat of tight sandstone reservoir block is narrow, and during the whole process of gas reservoir development, the water phase trapping damage is easy to prone, which restrict the development process of tight gas. The field test and laboratory experimental study have proved that the heat treatment technology for reservoirs can remove this damage and increase the permeability, but it has not been popularized and applied because of the unclear reservoir physical properties. Therefore, typical tight sandstone cores in Kuqa Depression, Huimin Depression and Jidong Depression are selected in order to simulate the fracture surface where heat treatment fracturing fluid stays or the near-wellbore zone where water phase gathers in the production process. A thermal shock experiment is carried out with 3 % KCL solution completely saturated experimental cores, the permeability of tight sandstone with different reservoir quality coefficient RQI before and after thermal shock is tested, and the relationship between the reservoir quality coefficient RQI and the increasing permeability is analyzed. The researches show that the permeability of tight sandstone samples does not change obviously when heated from room temperature to 100 ℃, but decreases slightly when heated to 200 ℃, and increases by 200 %~500 % when heated to 300~400 ℃, but the permeability of some samples does not change obviously, which is related to the reservoir quality coefficient RQI of the samples. The critical value of quality coefficient of water-bearing tight sandstone reservoir suitable for thermal surge permeability is 0.25. When RQI value is less than 0.25, the thermal surge permeability amplitude of rock samples is monotonically decreasing with RQI value. When RQI value is constant and heat shock temperature is greater than 200 ℃, the higher the temperature, the better the effect of thermal surge infiltration.

The formation water of Lower Palaeozoic gas reservoir in Daniudi Gas Field is high-salinity and acidity, and downhole throttling technology is mostly used. Thus, the amphoteric foaming agents widely used in gas fields has poor foaming and foam stabilization performance, and this cannot meet the demand for high-efficiency and low-cost drainage gas recovery. Although dozens of foaming agents have been formed internationally, there is no reports about foaming agents developed for the characteristics of Lower Palaeozoic reservoir of Daniudi Gas Field. Considering the fluid and process characteristics of Lower Palaeozoic reservoir, and the influence of high-salinity formation water, the sensitivity to pH and the stability of foam passing through the choke, to construct a new type amphoteric-nonionic compound foaming agent with sulfonated AEO₃ and lauramide propyl phosphobetaine as the main agent, coconut oil fatty acid monoethanolamide as the foaming aid, and sapindus extract as the foam stabilizer. The indoor evaluation shows that the amphoteric-nonionic composite foaming agent has strong foaming, stabilizing-foam, secondary foaming and liquid-carrying ability under high-salinity and acidic; after the field test application, the well drainage capacity improved, the pressure difference with tubing to casing decreased, and the gas production increased. It is shown that its application effect and economic benefits prospects are good. The amphoteric-nonionic composite foaming agent fills the void of the foaming agent for Lower Palaeozoic gas reservoir in Daniudi Gas Field, improving the technical problems of insufficient liquid-carrying, and has the value of popularization and application.

In order to solve the problems that the natural cracks of the dense sandstone reservoir in Sichuan region is undeveloped with low hole, low permeability and strong spatial heterogeneity, the transformation idea of “segment clusters created + sand + high strength long slot” is established by the indoor model experiments. On this basis, a calculation model of stress field around the wells based on the effective stress theory is established. Meanwhile, the above model is combined with the flow-stress coupling fracture extension model for horizontal wells to clarify the influence mechanism of cluster spacing on the crack competition expansion and interseam seepage interference. Therefore, the non-uniform arrangement method of cracks in the sand body of river channel considering stress interference and seepage shadow is formed. It is concluded that the optimal spacing of multiple clusters in the horizontal well section of dense sandstone in Qiulin is seven to twelve meters, which can make the opening rate of the injection cluster up to 92.3 %. This method effectively improves the effect of the transformation of the tight gas reservoirs.

Efficient development of Zhongjiang gas reservoir is faced with four difficulties: the meticulous channel depiction, the establishment of high-yield enrichment mode, the formulation with development technology policy, and corresponding engineering fracturing technology. For the narrow channel sand bodies, the multi-domain and multi-attribute fine description and accurate reservoir prediction technology are used, and the spatial distribution characteristics of multi-stage and overlapping channel sand bodies are well described. It can depict the channel sand bodies of the thinnest 8 m and the narrowest 50 m, and the sedimentary time sequence of each channel sand body is also very clear. An improved three-parameter pre-stack inversion technique based on ray parameter domain is used to realize the high-precision quantitative prediction of thin-layer, the predicted error of reservoir thickness and porosity is less than 10 %. By establishing an effective combination model of source rock fault and channel sand, with high ancient and modern structures or high ancient and low modern structures, and good reservoir physical properties, it is expected to obtain high and stable production of gas wells in these areas. By using the techniques of 3D deployment of well groups, well pattern optimization and horizontal well optimization design, the production degree of tight sandstone gas reservoir in narrow channel is greatly enhanced, and the investment cast is saved. By using the integrated horizontal well fracturing technology, the single well test gas production is steadily increased, and the transformation effect is increased to 10.6 times before implementation. High-efficiency development technology of tight sandstone gas reservoir formed by narrow channel enables efficient exploration and development of the Zhongjiang Gas Field, the largest gas field of Sinopec in western Sichuan, with an annual gas production of more than 1 billion cubic meters.

In order to understand the influence of displacement pressure on the gas flow capacity for different types of reservoirs and clarify the reasonable production pressures of different types of reservoirs, the tight sandstones of the main reservoir type Ⅱ and Ⅲ in the Xujiahe Formation of Danfengchang Gas Field are taken as the research object. And with the help of the NMR technology, the gas-flooding experiments of the tight rock samples of the two types of reservoirs under different displacement pressures are carried out to analyze the effect of displacement pressure on the gas flow capacity. The results show that the the pore structure and the displacement pressure difference have different effects on the gas flow characteristics of the rock samples in type Ⅱ and type Ⅲ reservoir. The gas flow characteristics of the rock samples in type Ⅱ reservoir are mainly affected by the displacement pressure difference. The greater the displacement pressure difference, the stronger the gas flow ability. And it mainly affects the flow ability in the small pore throat. While the pore structure and displacement pressure difference of type Ⅲ reservoir rock samples affect the gas flow characteristics together. When the capillary pressures of the layers are close to each other, the gas flow capacity is the best. Therefore, for tight sandstones in different types of reservoirs in Danfengchang Gas Field, the best production pressure should be used to achieve the best gas flow capacity during production.

The JS₂² gas reservoir in the Xinchang Gas Field is the microfacies of distributary channel deposit in the delta front subfacies. The mudstone interlayer developed in some sandstone layers form the channel sediments twice. For some gas wells with double developed sand layers, the perforation and fracturing are carried out only in one of the two layers, while the rest may be blocked by mudstone interlayer, resulting in its untapped situation. However, the understanding of the distribution rule of the mudstone interlayer is unclear, and the sealing performance of interlayers hasn't been verified by precedent, limiting the development of the remaining gas in this reservoir. By the establishment of the logging curve identification standards of the interlayer, the interlayer of every single well is identified and divided, and the development scale and plane distribution rule of the interlayer are studied. And then, the old wells are used to explore the vertical sealing performance of the mudstone interlayer inside the channel sandstone. The study results show that the mudstone interlayer, with the thickness of 1~15 meters, is mainly distributed in the east of the JS₂² gas reservoir, and has the characteristic of one thin-line area laying between two thick areas along the distribution direction. In the application of potential tapping of Well-A1, the production obviously increase after the perforation and sand-fracture, firstly verifying that the mudstone interlayer with the thickness of 10 meters in A1 well area has better vertical sealing performance. This achievement will provide new ideas and practical basis for the development of remaining gas in the JS₂² gas reservoir, and is of great significance for improving the recovery rate of the entire gas reservoir.

M area in Nanpu Oilfield is the main water injection development block of Jidong Oilfield, and it has entered the middle water cut stage at present. The water injection effect in the main area is remarkable, but in some areas, the effect is not obvious due to the unclear understanding of inter-well sand body connectivity, and the utilization degree of water injection reserves is low. An accurate evaluation of inter-well sand body connectivity is of great significance for improving injection and production well pattern and enhancing oil recovery in this area. The sand bodies in this area change rapidly in transverse direction, and the number of layers in longitudinal direction is large and small, thus it is difficult to recognize the inter-well sand body connectivity. In order to solve this problem, the inter-well sand body connectivity is evalued by the multi-disciplinary comprehensive technology including including seismic phase technology, seismic attribute technology, seismic inversion technology and reservoir performance analysis technology. With the combination of well, seismic and reservoir, this technology has been widely used to determine the inter-well sand body connectivity in this area, and achieved good results in development practice. The research improves the accuracy of inter-well sand body connectivity evaluation, and provides a favorable basis for guiding reservoir development adjustment in this area. It is of good reference for the evaluation of the inter-well sand body connectivity in the same type reservoir.

The cave is the main reserve space in fracture-cavity carbonate reservoir. The basic method of fracture-cavity reservoirs exploitation is to generate hydraulic fractures connecting the boreholes and caves through hydraulic fracturing. Based on the TOUGH-AiFrac coupling solver, the influence of different water injection pressures and internal pressure of caves on hydraulic fracture propagation is studied respectively. The results show that with the increase of water injection pressure, the influence of in-situ stress on hydraulic fractures is gradually weakened, and the fractures tend to initiate and propagate along the initial direction. When the water injection pressure is 1.6 times greater than the horizontal maximum principal stress, the rangeability of the fracture initiation directions weaken obviously, and the fracture direction tends to be stable. When the water injection pressure is 2.4 times greater than the horizontal maximum principal stress, the fracture propagation path tends to be stable. The greater internal pressure of the caves, the stronger the cave’s effect on hydraulic fractures. The caves with internal pressure reaching two times of the maximum principal stress exert a kind of “attraction” effect on the hydraulic fractures, which will be gradually strengthened with the increase of cave’s internal pressure while be weakened with the increase of injection pressure. The research results can be used as a guideline to optimize the fracturing work parameters and thereby enhance the oil/gas production rate according to the geological conditions.

The sufficient bottom water energy and complex rhythmic layer distribution in the lower oil formation reservoir of 9th block of Tahe Oilfield lead to the great difficulties of the conventional numerical simulation technology to characterize the complex bottom water rising regulation and the effect of EOR measures. Taking the lower Triassic oil formation reservoir in 9th block of Tahe Oilfield as an example, the high-precision numerical simulation technology under the background of non up-scaling geological model is introduced. By the early movable water simulation, single diaphragm flow, multiple diaphragm flow and dynamic relative permeability techniques are deployed. Then, the reservoir history matching research is carried out, and the overall production matching degree of the reservoir reaches 95.23 %. At the same time, the high precision numerical simulation technology is used to predict the field rate enhancement and gas injection measures, which is highly consistent with the field production effect. In the process of high-precision numerical simulation, the water breakthrough mode of horizontal well is changed from water ridge in conventional simulation to “water-breakthrough at point” mode. The main controlling factor of flow field is the collaborative control of pressure field and physical parameter field.