The Chang 6₁ reservoir was the main oil-bearing beds in the study area of Ganguyi Oilfield in Ordos Basin. The exploration and development practice showed that the reservoir characteristics had strong heterogeneity in three-dimensional space, and the vertical and horizontal distribution of the reservoirs were complex, which directly restrictsed the subsequent rolling exploration and development. In the study, based on the core observations and logging data, and combined with analytical testing, the controlling effect of the reservoir macroscopic heterogeneity on the oil layer distribution was systematically and visually analyzed. The complexity of the Chang 6₁ reservoir in the study area was caused by a variety of factors. Among them, the distribution of the sedimentary microfacies and diagenetic facies directly controlled that of the high quality reservoirs. And the interlayer heterogeneity, especially the interlayer permeability, was easy to cause the selective filling of oil, while the interlayer heterogeneity directly caused the heterogeneous distribution of oil in composite sand body. Through this study, the distribution law of ultra-low permeability and ultra-low permeability reservoirs in Ordos Basin could be better understood intuitively, which provides guidance for finding favorable zones in the future.

The commonly used water flooding characteristic curves are suitable in describing the water flooding laws in the middle-high water cut periods. However, these curves can hardly describe the water flooding characteristics of low and high water cut periods because of their theoretical basis of exponential expression of relative permeability curves and approximation during the derivation process. The applications showed that, for different reservoir characteristics and the water cut rising features, the conventional water flooding curves mighe shew as no straight line in the low water cut period and raise in the high water cut period, which resulted in poor fitting effect. So we proposed a new type of water flooding characteristic curve based on a new kind of widely applicable expression of relative permeability curve. This new curve could accurately describe the production dynamic rules under different water cut stages and directly calculate the recoverable reserves by fitting parameters. Applications showed that, by this method, the fitting straight line appeard earlier, the correlation coefficient was high, and the fitting effect was good. It had good applicability in different water cut stages, could describe the characteristics of water flooding more accurately and could easily predict the recoverable reserves. There was good application value in the dynamic analysis and making the production strategy of oil fields.

The following problems stood out in the deliverability tests and analysis of gas wells with high temperature and high pressure（HTHP） in South China Sea. Firstly, it was unable to accurately calculate the variable mechanical skin factors, resulting in the negative slope of deliverability equation, bringing about inaccurate calculation of the absolute open flow of HTHP gas wells. One new simulation technique, mainly consisting of variable skin analysis and productivity numerical simulation, for HTHP gas wells was proposed, and then the real damage could be evaluated accurately. In addition, the absolute open flow of HTHP gas wells was calculated based on flowing pressure and rates data in deliverability test simulation, eliminating the negative slope of deliverability equation. This simulation technique had been applied successfully well-X1 of HTHP gas reservoir in South China Sea, providing guidance for gas field production.

The start-up pressure gradient existed in the ordinary heavy oil reservoir, the seepage rules could not satisfy the Darcy's rule, and the theory of conventional water production rule was difficult to apply in the ordinary heavy oil reservoirs. On the basis of non-Darcy percolation rule, and the theory of the flow tube method and the oil-water two-phase non-piston water flooding, we derived the calculation formulas of water cut and recovery degree of heavy oil reservoirs in narrow channels, and analyzed the water cut rising rules. The results showed that if the viscosity of crude oil was high, the starting pressure gradient would be great, the rate of water cut would be fast, the width of water sweep zone would be small, and the oil recovery would be low. The reasonable injection and production parameters of narrow channel reservoir could be obtained by the model, which had certain guiding significance for actual reservoir development.

The conductivity of acid cracks was the key to the transformation effects of acid fracturing. Due to the influences of rock properties, etching morphology and closing pressure, it was difficult to accurately predict the conductivity of acid fractures. Currently, there were many computational models for acid fractures geometry and acid penetration distance, but there were few researches on the computational model of flow capacity. For this reason, we built the acid fracturing model of cracks based on the improved self-affine fractal theory and applied it to the fractal fractures. And then, by the local cubic law（LCL）, we built the acid fracture conductivity calculation model and applied the quadrature analysis to the main factors which affected the conductivity of the acid fracture after closure. The results showed that the influencing degree of those factors which affected the acid fracture conductivity were as follows: closure stress>fractal dimension>injection time>matrix permeability>injection rate>standard deviation>matrix porosity.

The polymer flooding blocks in Daqing oilfield had entered the subsequent stage of water flooding development. Due to the long-term water polymer flooding, the preferential seepage channels in the oil layers were highly developed, and the inefficient and ineffective circulation were serious. In order to achieve the goal of further EOR after polymer flooding, the dominant seepage channels must be accurately identified and effectively blocked. The conventional description methods, such as the coring, logging, profile testing and production performance, were with few and discontinuous data, low accuracy and high cost. As it was difficult to identify, by the streamline numerical simulation technique, and based on the study of typical blocks, we screened the key parameters and established the permeability time-varying model and mathematical model of comprehensive identification index. Then according to the initial value iterative method and combined with expert experience, we proposed the weight of the key parameters. At the same time, the dominant seepage channels were quantitatively graded according to the comprehensive identification index. The results showed that the calculated distribution of dominant seepage channels in typical blocks were highly consistent with the actual water absorption profile test results, which meant that the established method could accurately describe the distribution law of dominant seepage channels after polymer flooding. The research had important guiding significance for identifying and effectively sealing the dominant seepage channels, and provides strong support for the further efficient development after polymer flooding

The fracturing fluid leak-off in the reservoirs with developed natural fractures had a comparatively great influence on hydraulic fracture structure, proppant distribution and formation contamination. However, the current mathematical model for fracturing fluid leak-off considering natural fractures almost ignored or simplified the clustered distributed natural fractures, which limited the applications of these models. So firstly, by the multiplicative cascade method, we established a two-dimensional fractal discrete fracture networks model which reasonably showed the clustered distribution of natural fractures. Then, the established fracture networks were transformed into homogeneous anisotropic equivalent continuum media through subdividing the fractured porous domain into small elements. Ultimately, a mathematical model of fracturing fluid leak-off in fractured reservoir was established based on the permeability tensor. The results showed that the the strike of fracture rich zone determined the direction of fracturing fluid leak-off and pressure propagation. As the fracturing fluid tended to filtrate along long fractures, it was suggested to seal the natural fractures near hydraulic fractures before fracturing treatments. Moreover, fracturing fluid viscosity had certain influence on leak-off velocity.

As a new type of foam stabilizing material, nano-particles can significantly improve the stability of foam. The research and application of nano-particles have been paid much attention by petroleum researchers. Considering the demand of water plugging technology in Bohai Oilfield, and guided by the theory of physical chemistry, polymer materials and reservoir engineering, we studied the evaluation of basic performance and the physical simulation of water plugging effect of nano-particle nitrogen foam system according to the geological characteristics and fluids of typical reservoirs in Bohai by technical means such as instrument detection, chemical analysis and physical simulation. The results showed that when the concentration of foaming agent（PO-FASD） and stabilizer（SiO₂ nano-particle AEROSIL380） were about 0.3 %, the foaming agent and foam stabilizer could form the three phase foam system with nitrogen in excellent performance. With the increase of the reservoir permeability gradation, the effect of water flooding development got worse, and the effect of foam plugging and increasing oil increased. While with the increase of the water flooding recovery, the effects of foam plugging and oil increasing effect were improved. However, if the viscosity of crude oil increased, the effects of foam plugging and oil increasing effect would get worse. Thus, we could find that the three-phase foam system has good plugging and liquid flow steering ability, especially suitable for high water cut reservoir high permeability layer water plugging.

Firstly, we established a 3D forward model of the vertical well when drilling in faults, the response of the array lateral logging was numerically simulated by the finite element method. And then, we analyzed the effects of different fault dip angles, fault distances, and surrounding rock conductivity on the characteristics of array lateral logging response in the drilling process of fault. The results showed that when in the drilling process of the fracture zone, the larger the fault dip angle was, the smaller the width of the fracture zone would be reflected by the apparent resistivity. As the array lateral logging equipment went deeper and the fault distance（≤4 meters） got greater, the measured apparent resistivity would be closer to the resistivity of the fractured zone and surrounding rocks. When under the same detection mode, the apparent resistivity would increase with the increasing of the resistivity of lower surrounding rocks. When the detection mode and the surrounding rock resistivity were the same, the apparent resistivity would decrease with the increase of the resistivity of the surrounding rock while drilling the footwall of fault.

The relative permeability curves of polymer flooding are important bases for the development index predicting the polymer flooding oilfield. Aiming at the low numerical simulation accuracy caused by the lack of the relative permeability of the polymer flooding in the offshore L oilfield, we determined the relative permeability curves of the polymer flooding by the non-steady-state method to compare the relative permeability of different core permeability and polymer concentration. The variation law of relative permeability curve of the polymer flooding was summarized as well. The experimental results showed that the permeability curves of the polymer flooding increased with the core permeability, the relative permeability of the oil phase decreased with the same water saturation, and the residual oil saturation also decreased. With the increase of the polymer concentration, the oil relative permeability of the same water saturation increased, but the residual oil saturation decreased. In the early stage of polymer flooding, the residual oil saturation decreased rapidly, while in the middle and late stages, the residual oil saturation decreased slowly. The research results provided guidance and basis for fine numerical simulation and development planning in offshore polymer flooding fields.

Due to the heterogeneity of the formation of injection wells in BZ oilfield, the single acidification and profile adjustment were impossible to increase the injection and decrease the interlayer contradiction simultaneously. So we studied the combined acidification and profile control system indoors. The supporting acid solution system was one-step acid solution system, and its performance such as retarding speed, inhibiting secondary precipitation, dissolution and compatibility were evaluated experimentally. And then, we obtained that the permeability recovery was good after single core acidizing. The main agent of profile control agent system is anionic polymer, and its acid resistance and core plugging ability were evaluated. A double-core clamping flow test device was used to simulate the non-homogeneous layerss and analyze the influence of the injection sequence of the profile control and acidizing on the combined treatment effect. The simulation results showed that the acidification effect after profile adjustment was obvious, the permeability improvement ratio of low permeability core was 1.52, the permeability improvement ratio of high permeability core was blocked, and the permeability improvement ratio was 0.29. The goal of starting low permeability core by reducing the permeability difference between layers was realized.

The minor principal stress of Sulige gas field was between 43 ~ 48 MPa, while the proppant always used in fracturing was 20/40 mesh ceramic with moderate strength. In order to evaluate the feasibility of replacing the ceramsite with the quartz sand, we analyzed the demand and current situation of fracture conductivity by numerical modeling and well testing data. On this basis, we studied the selection of quartz sand and the mixed mode of quartz sand and ceramsite by indoor experiments, thus proposing the corresponding plan and carrying out the field tests. The results showed that, firstly, the present fracture conductivity was about 130 μm ²·cm, which was higher than the demand of the reservoir in class I（94 μm ²·cm）, the reservoir in class Ⅱ（65 μm ²·cm） and the reservoir in class Ⅲ（25 μm ²·cm）. The quartz sand was available for fracturing. Secondly, the uniform mixing of the 20/40 mesh quartz sand and ceramsite was a good combination way of proppant. When the closing pressure was between 40 ~ 50 MPa and the proppant placement concentration was 10 kg/m ², the conductivity of these who in the proportion of 1∶0, 7∶3, 1∶1, 3∶7 respectively were 20 % ~ 46.7 %, 23.9 % ~ 56.7 %, 46 % ~ 74.6 %, 73 % ~ 89.7 % of that of ceramsite. Thirdly, the optimal mixed proportion of quartz sand and ceramsite for the reservoir in class I should be below 1∶1. The optimal mixed proportion for the reservoir in class Ⅱ should be below 7∶3. The quartz sand could be used throughout for reservoir in class Ⅲ.

Based on the systematic collection of outcrop and drilling data, we evaluated the sedimentary facies of the lower Yangtze and the favorable zone. According to the researches, we found that the basin facies and the continental shelf facies were the favorable facies for the development of the hydrocarbon source rocks. Thereinto, in the upper Sinian, they were distributed in Wannan and Changzhou-Shanghai; in the lower Cambrian, they were in Chuzhou, Yancheng, Shitai-Anji and Dexing-Tonglu; in the lower-middle Ordovician, they were in Wuxi-Nanshan; in the lower Silurian, they were in Wuwei-Nanjing and Ningguo-Changxing. The favorable facies of lower ancient reservoirs were the marginal facies of the platform and the shallow facies of the restricted platform. Thereinto, in the upper Sinian, they were distributed in Wuxi-Yixing-Dongzhi and Wuwei-Taizhou; in the middle and upper Cambrian, they were in Wuxi-Yixing-Dongzhi and Ningzhen-Chaoxian; in the lower Ordovician, they were in Jingxian-Wuxi and Chaohu-Taizhou. The favorable facies of the lower Paleozoic mainly included the lower Cambrian, lower Silurian basin and continental shelf facies. Two sets of conventional reservoir assemblages could form in the lower Paleozoic of the lower Yangtze. One was taking the mud rocks in Sinian-lower Cambrian as the sours rocks, the dolomite in Dengying formation of Sinian as the reservoir, and the mud rocks in Hetang formation of lower Cambrian as the source-reservoir-cap rock group of cap rocks. The other was taking the mud rocks in Hetang formation of lower Cambrian as the sours rocks, the limestone and dolomite in middle-upper Cambria-Ordovician as the reservoir, and the mud rocks in Gaojiabian formation of lower Silurian as the source-reservoir-cap rock group of cap rocks. After the comprehensive assessment, Rugao-Sheyang area and Wangjiang-Liyang area were the the favorable area for gas reservoir exploration in lower Paleozoic.

In order to improve the production efficiency of coal-bed methane with low permeability, we proposed the CBM fracturing and recovery technique with pulsed discharge in water, studied the mechanism of high-voltage electrical pulse discharge in water and the fracture mechanism of coal fractures, and calculated the numerical simulation of energy by RFPA-Dynamic. The results showed that under the same hydrostatic pressure, and with the increase of discharge energy, the fissures increased, the fissure length got longer, the width got wider, and the fissure density around the borehole got larger. The tip stress of the fissure increased with the loading time and the discharge energy, so that the fissures expanded more easily. The research results could provide certain theoretical basis for the exploitation of CBM.

In this paper, we proposed the interpretation thought and method for the tight sandstone gas reservoirs. Firstly, we took the comprehensive evaluation method, combining the traditional quantitative interpretation with the special evaluation and the analysis of geological background to establish the parameters of rock electricity evaluation by dividing structure and deposition. Then, we used the variation of porosity to establish the variation of rock electrical parameters. Based on the analysis of reservoir lithology, physical property background and sensitive curve characteristics, we used the gas bearing attributes of three kinds of porosity curves to identify the gas reservoir attributes. By comparing with the test data and a large number of test results, the accuracy of gas reservoir identification was improved obviously.

Sublevel fracturing with sand of horizontal wells is an important method for the development of CBM. Combined with the fracturing construction examples in Zhijin district, we analyzed the reasons of the sand plug in fracturing and proposed the corresponding measures, thereby, to improve the success rate of the construction and achieve the purpose of reducing the cost and increasing the efficiency. It provided technical guarantee for the development of CBM wells in Zhijin area.