Ultra-deep fractured tight sandstone reservoirs are key targets for natural gas development, where gas flow is controlled by pore structure, capillary forces, and water saturation. Using the ultra-deep tight sandstones from the Tarim Basin as study object, this paper investigates the gas flow behavior in matrix and fractured cores under high-temperature, high-pressure, and various water saturation conditions. The controlling factors of gas flow are investigated through scanning electron microscopy, casting thin-section, and high-pressure mercury intrusion measurements. The results show that increasing the water saturation can significantly reduce the permeability. The permeability of matrix and fractured cores decreases by 71.15% and 79.67%, respectively, when water saturation reaches 50%. The gas slippage is negligible, but the effect of gas threshold pressure is significant, which is primarily controlled by the pore structure and water saturation. The threshold pressure gradient of gas flow ranges from 0.0004 to 0.8762 MPa/cm, with the matrix cores exhibiting values approximately 13.21 times higher than the fractured cores. The water phase preferentially occupies the larger pores, forcing gas flow to rely on the finer pores. The pores with a maximum radius of 0.21 μm require 0.66 MPa of driving pressure for gas, whereas pores with a median radius of 0.033 μm require 4.18 MPa. The fracture networks can significantly reduce the lower limit for gas flow, serving as the key flow channels for the efficient development of ultra-deep tight sandstone gas. These findings not only reveal the gas flow mechanisms under water invasion but also provide theoretical and practical guidance for enhancing gas recovery from ultra-deep tight sandstone reservoirs.

Ultra-deep tight sandstone gas reservoirs are key targets for natural gas exploration, yet their pore structures under high temperature, pressure, and stress greatly affect gas occurrence and flow. This study investigates representative reservoirs in the Kelasu structural belt, Tarim Basin. Porosity–permeability were measured under in situ conditions, and multi-scale pore structures were analyzed using thin sections, a SEM, mercury intrusion, and nitrogen adsorption. The results show that (1) the median permeability of cores at an ambient temperature and a confining stress of 3 MPa is 13.33–29.63 times that under the in situ temperature and pressure conditions. When the core permeability is lower than 0.1 mD, the stress sensitivity effect is significantly enhanced; (2) nanopores and micron-fractures are well developed yet exhibit poor connectivity. The majority of a core’s porosity is derived from the intergranular pores in clay minerals; (3) the volume of nano-sized pores within the 100 nm diameter range is mainly composed of mesopores, with an average proportion of 73.37%, while the average proportions of macropores and micropores are 22.29% and 4.34%, respectively; (4) full-scale pore sizes show bimodal peaks at 100–1000 nm and >100 μm, which are poorly connected; (5) the pore structure exhibits distinct fractal characteristics. The fractal dimension Df1 (2.65 on average) corresponds to the larger pore diameters of the primary intergranular pores, residual intergranular pores, and intragranular dissolution pores. The fractal dimension Df2 (2.10 on average) corresponds to the grain margin fractures, micron-fractures and partial throats. The pore types corresponding to the fractal dimensions Df3 (2.36 on average) and Df4 (2.58 on average) are mainly intercrystalline pores of clay minerals and a small number of intraparticle dissolution pores. These findings clarify the pore structure of ultra-deep tight sandstones and provide insights into their gas occurrence and flow mechanisms.

Phase behavior of hydrocarbon fluids in nanopores is different from that observed in a PVT cell due to the confinement effect. While scholars have established various models for studying the phase behavior in nanopores, the authors often ignore the effect of pore geometries, which can significantly affect the critical fluid properties in shale nanopores. In this study, we extend the Soave-Redlich-Kwong equation of state (SRK EOS) using potential theory and establish models of critical property shift, considering pore geometries, adsorption, and water film. Our research shows that the critical property shifts, considering fluid adsorption, begin at rp ≤ 10 nm and are seriously strengthened with nanopore radius reduction. The extended SRK EOS is applied to compute phase diagrams of the 50% C1-50% nC10 mixture at different pore sizes and find that the thickness of adsorption and water film causes a depression in the P-T diagram and that the bubble point pressure is lower in cylindrical pores. At pressures above 6 MPa, the irreducible water saturation and pore geometries greatly impact the vapor-liquid ratio. This study is significant for evaluating residual oil distribution and studying fluid flow laws in shale reservoirs.

The aim of this paper is to describe the pressure dynamic behaviour around a multilateral horizontal well in bottom water reservoir and get the productivity by establishing an analytical transient flow model. An exact solution of the model is derived by means of orthogonal transformation, method of mirror images and the theory of potential superimposition. For bottom water reservoirs, there is a supplementary boundary for the water aquifer. Given enough time, the transient flow will change to steady flow gradually. Correspondingly, the productivity index for wells in bottom water drive reservoirs can be calculated. We conclude that the analytical solution to the model can provide a valuable tool to compute the productivity and pressure dynamic behaviour of the multilateral horizontal wells in the bottom water reservoirs. Moreover, the case study shows that the calculated results agree with the practical situation. [Received: August 12, 2017; Accepted: March 16,2018]

In order to simulate the flowing of shale gas in multi-scale media, we established a mathematical model for the unsteady seepage of multi-stage fractured horizontal wells in shale gas reservoirs in consideration of the flowing characteristics of shale gas in matrix, natural fractures and large-scale artificial fractures. Grid division in the simulation region was carried out by means of nonstructural tetrahedral grid. Then, a 3D numerical model for the seepage of shale gas was established discretely using finite volume method and solved using sequence solution method. Finally, the production performance of multi-stage fractured horizontal wells in shale gas reservoirs and the reservoir pressure distribution were simulated, and the simulation results were analyzed. And the following research results were obtained. First, the gas production rates of multi-stage fractured horizontal wells calculated by this newly established numerical simulation method are basically consistent with the calculation results by the commercial numerical simulation software Eclipse, which proves that this new model is accurate and feasible. Second, the gas production rates of horizontal wells calculated by the sequential solution method are different from those calculated by the fully implicit solution method in the early production stages, but as the calculation progresses, both of them tend to be consistent, which further verifies the accuracy of this new model. Third, desorbed gas plays a supplementary role to reservoir pressure, but its function is limited, and its effect on gas production is little. As the production goes on, the percentage of desorbed gas increases gradually. Fourth, the key to the stimulation of shale-gas horizontal wells is to determine the number of fractured sections rationally and create longer artificial fractures. In conclusion, the research results are conducive to the design of stimulated reservoir volumes (SRVs) of shale gas reservoirs and the prediction of production performance of multi-stage fractured horizontal wells.

•We present efficient closed-form representations of molar entropy and Gibbs free energy for pure substances.•Present molar entropy and Gibbs free energy prediction models are only involving three molecular constants.•We excellently predict molar entropies and Gibbs free energies for the N2 gas.

针对裂缝性储层中裂缝分布的强非均质性和多尺度性,提出了一种多尺度离散裂缝两相流动模型的数值求解方法.该方法将n维模型中大尺度裂缝降维处理成n-1维实体,并基于格心形式的有限体积法对模型进行了离散,建立了数值求解格式,这些处理方法对降低求解时间及内存需求有显著影响.该方法具有严格的物理意义,保证了模型在局部范围内仍然遵循守恒定律.通过建立上游权值的有界高阶迎风格式,解决了一阶迎风格式所产生的假扩散现象以及大尺度裂缝与基质-微裂缝界面处饱和度突变引起的非物理振荡.使用IMPES顺序求解法对模型进行求解,通过结果对比证明了模型准确性.

The existing predicting models are established on the bases of the middle-high permeability oil reservoirs or without the stratigraphicdip angles,but the actual edge-water reservoir must have the angle.So the effects of the gravity action resulted from the angle cannot be ignored.Based on the theory of water-oil two phase fluid mechanics,the low-permeability inclined edge-water reservoir model was established in line with the actual situation and moreover the predicting formula of the water breakthrough time was derivedfor the horizontal wells in the reservoir,considering the following factors:the starting pressure gradient,stratigraphic dip,oil-water density difference,distance between the horizontal well and edge water,the horizontal well perforated length and so on,and furthermore each influencing factor was analyzed one by one.The analysis results show that compared with the existing formula of predicting the water breakthrough time,the calculating and predicting method in this paper is more close to the actual situation.It has important guiding roles for the studies on the mechanism of the edge water tonguing and the production management of the low-permeability inclined edge-water oil reservoir.

Water coning is easy to appear in heavy oil reservoir with bottom water, which results in earlier water breakthrough and great difficulties to the development of the reservoir. So it is very important to determine the critical production rate of oil well. At present, most of the calculation methods for critical production are established without start-up pressure gradient. A new method for calculation of critical production for heavy oil reservoir is established in this paper, considering start-up pressure gradient. Through instance analysis, it can be seen that this calculation method is more accurate and better meets the actual situation of the field, and has quite important guiding significance.

The interwell interference often affects the accuracy of the prediction results of water breakthrough time in a bottom water reservoir with smaller well spacing. Based on superposition principle of potential function, a new prediction formula considering the phenomenon of well interference is set up to explore the effects of the distance between adjacent wells and oil well production on water breakthrough time. The results show that smaller distance and greater oil well production would cause bigger interference and earlier water breakthrough time. The influence of the output and well spacing of the well on the water breakthrough time of the well decreases with the increase of the well spacing.

At present,the prediction of the water breakthrough time for the low-permeability bottom-water oil reservoir does not considerate the stress sensitivity,based on the seepage characteristics of the reservoir and characteristics of the stress sensitivity of the reservoir media,the predicting formula of the water breakthrough time was deduced considering the influences of the factors such as the stress sensitivity and so on.And moreover,the influences of the sensitivity,start-up pressure gradient and oil/water viscosity ratio on the time were analyzed.The studies show that the bigger the stress sensitivity coefficient is,the earlier the bottom water breakthrough will be;with the increase of the start-up pressure gradient,the pressure difference between the bottom water and bottom of the well also rises and the breakthrough time is ahead of the time;the larger oil-water viscosity ratio is,the earlier the water breakthrough time will be;the water breakthrough time is ahead of the time with the increase of the well production.So the reasonable design of the well production can prolong the water-free production period of the oil well.

整装油藏在长期注水开发中,强注强采导致油水井间逐步形成优势流场,即水驱油流动的主流线.在特高含水期,主流线方向上水洗程度较高,剩余油饱和度较低.因此在开发后期只有打破原来的固定优势流场,使得注入水向弱势区流动,才能有效驱动原油,提高地层原油采收率.通过大尺度物理模型实验,改变特高含水后期注水流场方向,分析剩余油分布情况及原油驱替效率.确定在同一井组,相同井距,相同采液速度条件下,九点井网是特高含水后期井网调整的最佳选择.