The Chang-2 reservoir of Ansai oilfield has the geological characteristics of low porosity, low permeability, fast change of physical properties and strong vertical and horizontal heterogeneity. Based on the ''four properties'' relation of reservoir, we established the minimum standards of effective thickness by using the core analysis, oil test, production dynamics and logging by the way of histogram method and cross plot method. Then we proposed the different types of interlayer logging quantitative identification chart and the elimination criterion of various interlayer on the basis of the semi-quantification and semi-qualitative analysis by many kinds of logging curves. The minimum values were as follows: the oil-bearing property was to see the grease spots; the lithological property was to see the fine-grained sandstone; the physical property were the porosity was more than or equaled to 11.5 % and the permeability was more than or equaled to 0.63×10 ^-3μm ²; the electrical property were the resistivity was more than or equaled to 13 Ω·m and the acoustic was more than or equaled to 230 μs/m. The main types of interlayer were calcareous interlayer and muddy interlayer. We could identify and eliminate the interlayer by the quantification of curves of natural gamma, acoustic and microelectrode, and the qualitative analysis of the curves of spontaneous potential, RILD, RILM, microsphere resistivity and micronormal.

At present, we cannot use the conventional gas reservoir productivity evaluation equation to accurately predict the abnormal high pressure and low permeability gas reservoir capacity. Based on this fact, we considered the actual seepage of abnormal high pressure and low permeability gas reservoirs and established a new physical model to regionalize the seepage zone of gas reservoir. By the novel pseudo pressure function and the principle of superposition, and on the basis of considering the critical radius of gas flow, high-speed non-Darcy flow of gas, pulse effect, reservoir permeability stress sensitivity and starting pressure gradient effect, a new abnormally high pressure and low permeability gas reservoir productivity equation was deduced, and the validity of equation by actual test date was tested. The results showed that the relative error between the calculation results of the conventional productivity equation and the actual capacity test results without considering the influence of seepage area and multi factors could be as high as 21.5 %. The relative error between the capacity calculation results of the new equation and the actual capacity test was less than 5 %, and with the decrease of the bottom hole flow pressure, the high velocity non-Darcy flow effect, the starting pressure gradient effect and the permeability stress sensitivity effect could lead to the serious decrease of the gas well production. However, the critical radius of gas low velocity and the effects of pulse on gas well productivity were small.

Pressure decline analysis for hydraulic fracturing is very important for the formation evaluation and the optimization of fracturing design. But in the practical application, some problems of the pressure decline analysis were existed such as the unverifiable closure pressure, inaccurate geometric parameters of fracture and lack of formation effective permeability. Another way of obtaining closure pressure based on analysis on the character of pressure decline after fracture closure was introduced to verify the analysis result of conventional methods at first. An optimization method to achieve the fracture geometric parameters was given on the basis of G-function and pseudo-3D fracturing model at the second. Then the method of achieving reservoir effective permeability with the pressure data of quasi-linear flow after fracture closure was proposed. At last, a case was analyzed with the improved method and the calculation results verify the suitability and accuracy of this method.

During the development process of gas reservoirs with high sulfur, when the pressure near the wellbore reduced to a critical value, the sulfur particles precipitated gradually and cloged the pores and fractures, decreasing the productivity of gas wells. Based on the fractal theory, this model for composite gas reservoirs with high sulfur, consisted of inner region and outer region, wass established. Taking wellbore fluid phase separation, wellbore storage factor, skin factor and varying permeability into consideration and by the Stehfest numerical inversion method, this model solved the bottom hole pseudo-pressure solutions in real space. Then with the assistance of Visual Basic 6.0 programming, the log-log type curves for pseudo-pressure and pseudo-pressure derivative were obtained. Finally, the influence of some factors such as skin factor, varying permeability index and mobility ratio on type curves were analyzed. The results had some essential practical significance.

Water generally exist in the gas well in west Sichuan gas field, which has a great influence on the steady production of gas wells. The timely grasp of the flow conditions of the gas wellbore can judge the fluid accumulation in gas well and guide the formulation of the drainage gas recovery measures. By using the pressure meter to judge the downhole conditions of the gas well had the disadvantages of poor timeliness and high cost, and the prediction of two phase flow theory often had deviations from the actual existence. So we used a large number of gas well production data and flow pressure test data to establish the prediction model of wellbore flow condition based on RBF neural network. The RBF network had the self adaptability and its output do not dependent on the initial weight. The coincidence rate between prediction results and actual results among 15 wells was 86.67 %, which indicated that the neural network model was reliable for predicting the wellbore flow conditions of gas well, and could be used to guide production.

In order to solve the problems such as the breakthrough of flue gas, frontal advance of combustion drive and conventional plugging technology do not meet the requirement of fire drive in the fire drive test area of Hongshanzui oilfield in Xinjiang. We used the device for testing the foam flow in core and the visual microscopic displacement model to study the flow experiment and the microscopic mechanism of flue gas foam. The experimental investigation showed: the gas-liquid ratio was an important factor that affects the capacity of foam blocking; the foam blockage ability was the strongest when the foam system was mixed with gas and the gas-liquid with ratio 1∶1; the oil recovery factor increased by 12.6 % after the flue gas foam injection. The microscopic mechanism research showed: the main reason why foam had the ability of blockage was the new foam blocked the big pore and increased the flow resistance of the fluid. The migration of foam in porous media was a kind of separate migration of gas phase and liquid phase; the trap and flow state of the foam were constantly transformed with the change of external conditions. The study can provide reference for the control of gas channeling in the fire flooding test area of Hongshanzui oilfield in Xinjiang and is helpful to improve the theory of bubble control.

Chang-3 layer in Weibei oilfield belongs to the middle-shallow reservoir, with the buried depth of 200 ~ 1 000 m. The fractures formed diring the fracturing have complex shape with horizontal joints, vertical joints and oblique crack, which impact the evaluation of the fracturing and fracturing effects. Taking Chang-3 reservoir in Weibei oilfield as the research object, combined with the reservoir rock mechanics and crustal stress experiment, and through the analysis of logging data and fracturing construction curves, we calculated the relative values of the vertical stress and horizontal stress and reveal the formation law of fracture forms, so that to summarize the fracture formation identify and prediction technology of Chang-3 reservoir in Weibei oilfiled. When the reservoir depth was less than 450 meters, the horizontal joints formed; when the depth was more than 550 meters, the vertical joints formed; when the depth was between 450 and 550 meters, the complex fractures formed. It was recommended to conduct the mini frac testing to determine the fracture forms.

After the guidance of the results of gas flow conductivity test for the optimization of fracturing design of tight gas reservoirs, the prediction of post fracturing effect and the optimization evaluation of proppant were more pertinent and reasonable. The current common gas flow conductivity tests mainly focused on the influence of the closure pressure, proppant particle size and proppant type on the flow conductivity. Based on the analysis, we designed the experimental scheme about the influence of fracturing fluid type and laying mode on gas flow conductivity by using the DL—2000 fracture support conductivity tester and according to the SY/T6302—1997 "proppant filling layer short-term conductivity evaluation and recommendation method". The results showed that the fracture conductivity decreases when the closure pressure increased; the larger the proppant diameter was, the greater the conductivity would be; while the greater the closure pressure was, the greater the decreasing amplitude of the flow conductivity would be. The laying mode for the rear gas logging fracture conductivity was the best. The fracturing fluid damage made the cracks in the gas logging diversion capacity decreased by 80 %~95 %.

In order to further explore the migration rule of alkali/surfactant/polymer（A/S/P） system in the reservoir, guided by the reservoir engineering, surfactant chemistry and oilfield chemistry, and aimed at the fluid properties and geological characteristics, we conducted the research on change rule of viscosity, IFT tension and displacement effect of A/S/P system, and discussed the relative mechanism based on the dynamic testing result of single component concentration of compound system. The results showed that during the displacement process of A/S/P system, the polymer, surfactant and alkali presented different along-range retention characteristics, the chromatographic separation phenomenon occurred, the decrease rate of surfactant concentration was much higher than that of polymer and alkali, and both the ultra-low interfacial tension and high viscosity could only keep the length of 1/3 well distance. The contribution rate of ultra low tension was limited in the A/S/P flooding; about 60 % oil was not recovered by compound system under the condition of ultra low tension. If the A/S/P system can keep lower IFT and give consideration to proper viscosity, we can acquire the better displacement effect.

During the drilling process in complex sections of the formation, due to the leakage of the drilling fluid, the borehole instability occurs easily. In view of this situation, we put forward the film formation and plugging project of the drilling fluid. In the indoor experiment, the microstructure of the mud cake was analyzed by scanning electron microscopy（SEM）. The hydration resistance of the plugging film was evaluated by the water permeation tests. The improved sand bed experiment had simulated the plugging performance of the drilling fluid on the formations with different permeability. Then, we analysed the positive pressure capacity and flowback effect of the plugging film by the self-designed unconsolidated sand core flow experiments. The experimental results showed that the film-formation drilling fluid was resistant to the highest temperature of 150 ℃, and the mud cake formed by API leak-off was denser. In the same period, the water permeability of the mud cake remained unchanged and the plugging film had certain hydration resistance. When the dosage was between 2 % ~ 3 %, the sand beds with different mesh were totally blocked, without the leak-off of the drilling fluid, and the positive pressure value was high after the plugging film formed, which could reach 16 MPa. In the reverse driving, the breakthrough pressure was between 0.5 ~ 1 MPa with good flowback effect.

The reasonable length of horizontal wells for lens-like thin-layered bottom-water reservoirs has been a question, and there were limited studies in the literature. Aiming at the study of a specific low amplitude, moderate-high permeability, thin lens-like sandstone reservoir with bottom-water in Hutubi river layer in Luliang oilfield of Xinjiang, by using a variety of methods in geology, drilling, reservoir engineering and numerical simulation, and combined with the effects of horizontal wells during the reservoir development, we demonstrated the relation respectively between various factors of horizontal well length and wellbore pressure loss, reservoir adaptability, and development of oil drilling rate effects of such reservoir. Then, we proposed the range of the reasonable length of horizontal wells considering both theoretically and practically. The results showed good reliability and applicability, providing technical reference for the research and application of horizontal wells in similar bottom-water reservoirs.

As one of the important source rocks in Tarim basin, Yuertusi source rock, whose thermal evolution history is still lacking of objective knowledge which restricting the choice of exploration direction. On the basis of drilling data and analysis test, the Easy%R_o model of basin modeling technology was used to analyze the thermal evolution history and its dissimilarity of Yuertusi source rock in different tectonic units, and the favorable exploration areas were raised, that was important to the further deep carbonate reservoir exploration. The results showed that the source rocks with multiphase and differences dynamic characteristics in thermal evolution were controlled by tectonic movement and hydrothermal activity. The source rock in the ring with depression of Manjiaer and Tanggubasi entered the hydrocarbon generation threshold successively in Ordovician, but the source rock in the Kongquehe slope and eastern Guchengxu uplift entered the stagnation of hydrocarbon generation in Silurian. The Shunxi to Manxi area entered the stage of hydrocarbon generation dried up in Permian and Carboniferous and the range of depletion has gradually expanded. The thermal evolution process of the source rock in the eastern Maigaiti slope significantly was later than that of other areas; it was still in the late mature stage today. The predicted favorable zones were west Shaya uplift, west lower uplift of Shuntuoguole, east Maigaiti slope and west Tanggubasi depression slope.

The property of low porosity and ultra-low permeability of shale gas reservoirs decide that only by the horizontal well fracturing can we obtain the economic productivity, and the forecast of the production after fracture have a great influence on optimal plan of treatments and economical estimation. On the basis of summarizing the previous researches, a novel model for production forecast in the unsteady early period was established based on the corrected Warren & Root model and considered about the desorption, slippage and stress sensitivity of micro fractures. Then the analytical solution for pseudo pressure was obtained by Laplace transformation and well-test method. Lastly, the practical production data was used to verify the accuracy of this model, and the factors affecting production were analyzed. The conclusion showed that the computed value and actual value of average daily production for single well in shale gas reservoir were similar to each other, demonstrating the validity of the model. Desorption and slippage had noticeable effects on the production and it also revealed that desorption played an important role in gas output. However, stress sensitivity could also affect the production in some extent, but the extent of the influence was less than that of desorption and slippage. The conclusions were meaningful for the study of output mechanism of shale gas and early production forecast.

Shale oil resources are rich around the world and have extraordinary exploitation prospects. However, drilling horizontal wells and huge amounts of hydraulic fracturing measures had sharply increased the cost. A large number of experiments and numerical simulations showed that the gas injection could significantly improve the shale oil recovery. Nevertheless, this technique had not been implemented to the practical exploitation of shale oil. Consequently, it was still controversial whether shale oil recovery could be optimized through gas injection or not. By the comparison of the gas displacement experiments of the shale cores, the numerical simulation of shale oil recovery by gas injection and the gas injection pilots in practical fields, it was found that the results from experimental conditions and numerical simulation models were different from those in field pilots. Li Chuanliang insisted that the shale reservoir was consisted of myriad micro-lithologic traps. It was concluded that only if the gas was injected after fracturing, or establishing an orthogonal horizontal well pattern to dense the well spacing, would the shale oil recovery be improved. It has essential guidance for the improvement of shale oil recovery in China or even in the world.

The oil and gas well data collection system has been widely used in the shale gas well testing. In the process of operation and management of data collection equipments, the sorting and recording of field data, reporting of field real-time and staged production reports all required to be operated by professional technicians. This work took a lot of time and was error-prone. Automatic report management was a technology combining the actual production of shale gas with the data collection system. Relay on Python, the computer programming language, we could obtain the field data and records, and on this base, compiled and sent reports. This technology can greatly improve the accuracy and efficiency of data recording, and reduce the labor intensity of technicians.