Non-Darcy flow in oil accumulation (oil displacing water) and relative permeability and oil saturation characteristics of low-permeability sandstones

Petroleum Science, Feb 2010

Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil (gas) saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone (oil displacing water), we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that: 1) Oil migration (oil displacing water) in low-permeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2) With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity is less than 1.0, the percolation curve is a “concaveup” non-Darcy percolation curve; 3) Oil-water two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4) The oil saturation of low-permeability sandstone reservoirs is mostly within 35%–60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity.

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Non-Darcy flow in oil accumulation (oil displacing water) and relative permeability and oil saturation characteristics of low-permeability sandstones

Pet.Sci. Non-Darcy flow in oil accumulation (oil displacing water) and relative permeability and oil saturation characteristics of low-permeability sandstones Zeng Jianhui 1 2 Cheng Shiwei 1 2 Kong Xu 0 2 Guo Kai 1 2 Wang Hongyu 1 2 0 CNPC Greatwall Drilling Company , Beijing 100101 , China 1 School of Natural Resources and Information Technology, China University of Petroleum , Beijing 102249 , China 2 State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum , Beijing 102249 , China Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil (gas) saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone (oil displacing water), we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that: 1) Oil migration (oil displacing water) in lowpermeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2) With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity is less than 1.0, the percolation curve is a “concaveup” non-Darcy percolation curve; 3) Oil-water two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4) The oil saturation of lowpermeability sandstone reservoirs is mostly within 35%-60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity. Non-Darcy flow; relative permeability; oil saturation; low-permeability sandstone 1 Introduction Actually, low-permeability sandstone is a relatively indistinct concept, which has not been strictly and precisely defined internationally yet. Berg (1975) suggested that the upper limit of low-permeability sandstone was 1×10-3 μm2-10×10-3μm2. The classification standards for reservoir properties of clastic rock and non-clastic rock issued by the Chinese National Committee on Mineral Reserves define a reservoir with porosity between 10% and 15% and permeability between 5×10-3μm2 and 50×10-3μm2 as lowporosity and low-permeability reservoir, while that with porosity less than 10% and permeability less than 5×10-3μm2 as super-low-porosity and super-low-permeability reservoir (Li, 1997) . The oil and gas resources preserved in low-permeability sandstone are very abundant and are extensively distributed all over the world. They can be found in almost every oilproducing country. A big quantity of low-permeability sandstone deep-basin gas reservoirs were discovered in the Los Angeles Basin and Powder River Basin of the US, Carpathians, Krasnodar, Urals-Volga and West Siberian oil province of the former Soviet Union, and the Alberta Basin in the west of Canada (Surdam, 1995; 1996; Law, 2002; Ayers, 2002; Williams et al, 1998) . In China, low-permeability sandstone reservoirs are common in almost all the oil and gas bearing basins, especially in the Ordos, Sichuan, Junggar, Tarim and Songliao Basins. According to the statistics of Jiang et al (2004 ), the petroleum resources in China amount to 940×108 t, of which 210.7×108 t (22.41%) occur in low-permeability sandstone. Among the newly increased proven reserves in recent years, low-permeability reservoir hydrocarbon reaches 70%, and the proportion is increasing. Low-permeability sandstone reservoirs have many different characteristics from conventional reservoirs. They are mainly distributed in the slope and syncline locations in basins without a definite trap boundary or caprock. Their reservoir rocks have low porosity and permeability or super low porosity and permeability (porosity less than 10% and permeability between 10-3 and 10-12 μm2). Hydrocarbon resources are extensive but unevenly distributed inside or near the source area with no migration or primary migration due to limited buoyancy effect. Under abnormal pressure (high or low pressure) and with no clear gravitational differentiation, oil-gas-water distribution is complex and hydrocarbon is locally accumulated with relatively low oil (gas) saturation (Law and Curtis, 2002; Ayers, 2002; Williams et al, 1998; Pang et al, 2002; Zhao et al, 2004; Zhang et al, 2006; Min et al, 1998; Wu et al, 2007; Yang et al, 2003; Zhang and Wang, 2003) . It is very difficult to explain the hydrocarbon distribution rule of low-permeability reservoir by conventional petroleum geology theory, which is probably related to the special pore characteristics and pore structure of low-permeability rocks and the special migration and accumulation mechanisms of the hydrocarbon in this kind of pores. In 1856, a French engineer, Darcy, suggested that, fluid percolation characteristics in porous media could be described with what would later be called Darcy’s Law, which argued that the pressure loss was totally determined by viscous force. In the middle period of the 20th century, the research results indicated that the flow of water and oil in soil, sand, porous ceramics, and underground reservoirs did not follow Darcy’s Law but behaved as a non-Darcy fluid, i.e., the percolation velocity and pressure gradient in the percolation movement expression showed non-linear relation, and a threshold pressure gradient existed (Miller and Low, 1963; Olsen, 1965) . During the last twenty years, with the extensive exploitation of low-permeability reservoirs, many scholars have studied by simulation experiments the percolation characteristics of oil and gas in low-permeability sandstone during the exploitation process, namely the water displacing oil process from the viewpoint of hydrocarbon production. The research results indicated that, fluid migration in lowpermeability reservoirs presented non-linear characteristics, and the oil-gas-water percolation behaved as a non-Darcy flow with a threshold pressure gradient (Yan et al, 1990; Li et al, 2003; Ruan and He, 1999a; 1999b; Yao and Ge, 2000; 2003; Deng et al, 2000; Cheng and Chen, 1998; Ren et al, 1997; Xue et al, 2001; Huang, 1997; 1998; Deng and Liu, 2006; Han et al, 2004; Huang et al, 2005; Wang et al, 2004; Pascal and Pascal, 1997; Prada and Civan, 1999; Li, 1997; Feng, 1986; Civan, 2000; Merrikh and Mohamad, 2002; Soni, 1978) . However, the research has mainly been about the nonDarcy percolation characteristics of water-displacing-oil from the viewpoint of single-phase percolation or hydrocarbon exploitation, while few people have studied the nonDarcy flow characteristics and the distribution of oil (gas) saturation in low-permeability sandstone from the viewpoint of hydrocarbon accumulation (oil/gas displacing water). Based on simulation experiments, we firstly determined the non-Darcy percolation curve of low-permeability sandstone (oil displacing water) and discussed its influencing factors; then, studied the value and change of relative permeability that was the key parameter characterizing the migration and accumulation of oil and gas in low-permeability sandstone; and finally, discussed the value, growth process and influencing factors of oil saturation of low-permeability sandstone under oil/water phase non-Darcy flow condition. 2 Non-Darcy characteristics of oil migration in low-permeability sandstones 2.1 Experimental methods and equipment The cores in the experiments were from the Yao1 Member in the Gulong Sag, Songliao Basin. First, the cores were washed free of oil with a solvent, and then dried. Second, the length, diameter, porosity and permeability of the cores were measured. Finally, the cores were vacuum-pumped and saturated with water (Zhu et al, 2009) . We added kerosene to crude oil to obtain experimental oil with different viscosities. The salinity of salt water is 6.0 g/L and viscosity is 1.005 mPa·s. The experimental temperatures were set at 70°C and 90°C (Table 1). The experimental equipment was composed of five parts, namely, fluid injection system, fluid displacement system, temperature and pressure control system, fluid measurement system, and data acquisition and processing system, with the experimental procedure shown in Fig. 1. We used the constant pressure method with simulated oil as the flowing medium, and conducted oil-displacing-water percolation experiments to study oil migration characteristics of low-permeability sandstone during reservoir formation. The experiment started from the minimum displacement pressure determined by the lowest flow velocity at the export end of cores, and when the export flow velocity ranged from 0 mL/min to 0.01 mL/min, the pressure could be regarded as the minimum displacing pressure. The pressure of the injecting pump was set in advance and was kept constant. The pressure differences between the import end and the export end of the rock sample at the flow velocity were measured with a sensitive pressure sensor, and the fluid velocity at the export end was accurately metered with an automatic fluid meter. The pressure difference and export velocity values were recorded every preset time interval (commonly 3-5 min). When the continuously recorded export velocity values stabilized around a specific value (the difference between two successive measured values was less than 2% continuously), it was considered that under a specific constant displacing pressure difference, the percolation velocity at the export end of the rock sample reached a stable state. Then the balanced pressure difference and export velocity values at such flow velocity were recorded. We gradually increased the injecting pressure, and when the pressure was stable, we recorded the corresponding pressure difference and flow velocity values. In the similar way, we selected ten different fluid injecting pressures and recorded relevant data respectively until the export end had no water flowing out. a: fluid injection system; b: fluid displacement system; c: temperature and pressure control system; d: fluid measurement system; e: data acquisition and processing system 2.2 Non-Darcy percolation curve for oil migration (oil displacing water) 2.2.1 Types of non-Darcy percolation curve for oil migration (oil displacing water) Results of the simulation experiments indicated that nonDarcy percolation curves for oil migration (oil displacing water) of low-permeability sandstone were mainly of two types (Fig. 2 and Fig. 3). (1) Modified non-Darcy percolation curve For the modified non-Darcy type of percolation curve, in the range of experimental flow velocity, the pressure gradient and flow velocity show a linear relation, and there is no nonlinear part of the curve. However, it is different from the Darcy percolation curve in that the straight line extrapolated in the opposite direction does not pass through the origin of coordinates. Fig. 2 shows modified non-Darcy percolation curves of simulated oil with fluid viscosity of 7.2 mPa·s (90°C) in core 119 (permeability: 7.86×10-3μm2), core 105 (permeability: 12.55×10-3μm2) and core 97 (permeability: 21.10×10-3μm2), respectively. (2) Concave-up non-Darcy percolation curve In the range of experimental flow velocity, this type of percolation curve consists of two gentle transition segments: 0.9 0.8 in 0.7 /m 0.6 Lm 0.5 ,y 0.4 itc 0.3 o le 0.2 V 0.1 0 concave-up non-linear percolation curve at relatively low percolation velocity and pseudo-linear percolation curve at relatively high percolation velocity. As shown in Fig. 3, the percolation curves are characterized by low-velocity nonDarcy percolation with a threshold pressure gradient, and the extension of the straight line segment has an intercept on the pressure gradient axis, which is the pseudo threshold pressure gradient. The curve segment is generally concave to the flow velocity axis. With an increase of the percolation velocity, the curve shows a transition from non-linear to linear. 2.2.2 Threshold pressure gradient One of the largest differences between non-Darcy percolation and Darcy percolation is the existence of a threshold pressure gradient (Miller and Low, 1963; Yan et al, 1990; Cheng and Chen, 1998; Ruan et al, 1998; Wu et al, 1999; Chen et al, 2003; Song and Liu, 2001; Yao and Ge, 2003; Li et al, 2005; 2007) . Results of the simulation experiments indicate that when oil accumulates and forms a reservoir (oil/water two-phase migration) in low-permeability sandstone, the threshold pressure gradient for non-Darcy flow has a minimum value of 0.010 MPa/cm and a maximum value of 2.9306 MPa/cm (Table 1). Though the threshold pressure gradient shows a relatively poor correlation with porosity, it presents a relatively good negative correlation with permeability (y=0.079x-0.6205, R2=0.8072). With the increase of sandstone permeability, the threshold pressure gradient decreases in a power function (Fig. 4). The reason might be that, compared with porosity, permeability can better reflect the permeable performance of rock and migration capability of fluid, thus leading to very good correlation between threshold pressure gradient and permeability. Since the migration of oil in low-permeability sandstone is actually the result of physical interaction between lowpermeability sandstone and fluid, threshold pressure gradient is not only related to the properties of the low-permeability sandstone, but also related to the properties of the fluid. Therefore, it is necessary to discuss the relation between threshold pressure gradient and apparent fluidity which is a parameter reflecting physical interaction between sandstone and fluid (ratio of rock permeability to fluid viscosity, k/μ). Fig. 5 shows that threshold pressure gradient is well negatively correlated with apparent fluidity (y=0.0196 x-0.6078, R2=0.8824). With an increase of apparent fluidity, the threshold pressure gradient decreases in a power function, showing a better correlation than that between threshold pressure gradient and permeability, which indicates that apparent fluidity can better reflect the changes of threshold pressure gradient during oil migration in low-permeability sandstone. 0.5 1 1.5 2 2.5 Apparent fluidity, ×10-3μm2/mPa∙s 3.5 2.3 Influencing factors of oil non-Darcy flow in lowpermeability sandstone Similar to the influencing factors of oil, gas, and water single-phase flow in low-permeability sandstone, the results of percolation experiments of oil-water two-phase migration indicate that fluid and sandstone properties, and interaction between fluid and rock jointly influence the percolation characteristics of oil-water two-phase migration in lowpermeability sandstone. 2.3.1 Fluid viscosity (μ) Fluid viscosity is a main factor influencing percolation characteristics of oil-water two-phase migration in lowpermeability sandstone. Results of the simulation experiments show that, when the core permeabilities are almost the same but fluid viscosities are different, the percolation curve characteristics are also different. The higher the fluid viscosity, the more inclined to the pressure gradient axis the percolation curve, and the longer the non-linear segment of the curve. The smaller the curvature, the bigger the intercept of straight line segment on the pressure gradient axis, and the more obvious the non-Darcy phenomenon (Fig. 6). To reach the same flow rate, a fluid with higher viscosity needs a higher pressure gradient. As shown in Table 2 and Fig. 6, core 79-2 (permeability: 0.85×10-3μm2) and core 45 (permeability: 0.82×10-3μm ) have similar permeabilities, while with the 2 increase of fluid viscosity from 7.2 mPa·s (90°C) to 19.2 mPa·s (70°C), the intercept of the percolation curve on the pressure gradient axis increases from 0.2476 MPa/cm to 0.3621 MPa/cm. Likewise, core 42 (permeability: 1.01×10-3 μm2) and core 112 (permeability: 1.42×10-3μm2) have similar permeabilities, while with the increase of fluid viscosity from 7.2 mPa·s (90°C) to 19.2 mPa·s (70°C), the intercept of the percolation curve on the pressure gradient axis increases from 0.1700 MPa/cm to 0.2847 MPa/cm. permeability. The curve is mainly modified non-Darcy percolation when the sandstone permeability is relatively high, while it is mainly concave-up non-Darcy percolation when the sandstone permeability is relatively low. 2) The lower the permeability, the more inclined the percolation curve is to the pressure gradient axis, and the 2.3.2 Porosity and permeability of low-permeability sandstones Results of the simulation experiments show that, under the same fluid viscosity condition, the percolation curve of oil-water two-phase migration has a complicated relation with porosity, but it is well related with permeability (Fig. 7 and Fig. 8), which is represented as follows: 1) The curve shape and position change regularly with Core: 75 Core: 63 Core: 79-2 Core: 42 Core: 82-2 Core: 124 Core: 119 Core: 105 Core: 97 Core: 45 Core: 112 Core: 46 Core: 80-2 0.2 0.4 0.6 0.8 1 Pressure gradient, MPa/cm 1.2 1.4 2.3.3 Apparent fluidity (k/μ) Apparent fluidity is the ratio of the rock permeability to the fluid viscosity (k/μ). Since oil migration in lowpermeability sandstone is the result of physical interaction between sandstone and fluid, it is necessary to discuss the influence of apparent fluidity on the percolation characteristics of oil-water two-phase migration. Results of simulation experiments indicate that, when the apparent fluidity is more than 1, the percolation curve is characterized by modified Darcy flow, and the relation curve of pressure gradient and flow velocity is linear with no non-linear segment. The extrapolated straight line does not pass through the origin of the coordinates. The higher the apparent fluidity, the more inclined to the flow velocity axis the straight line. It is indicated that under the same pressure gradient, the larger the increase of flow velocity, the more easily percolation occurs (Fig. 9). When the apparent fluidity is less than 1, the curve is characterized by typical concave-up non-Darcy percolation, whose shape and position change regularly with changes in apparent fluidity. The lower the apparent fluidity, the more inclined the percolation curve is to the pressure gradient axis, and the longer the non-linear segment of the curve extends. The smaller the curvature, the lower the slope of straight line segment of the curve, and the larger the intercept of straight line segment on the pressure gradient axis. Thus, the higher the threshold pressure gradient, the more obvious the nonDarcy phenomenon (Fig. 10). lower the slope of straight line segment. 3) With a decrease of permeability, the non-linear segment of the curve extends longer, the curvature decreases, and the intercept of the straight line segment on the pressure gradient axis increases. The higher the threshold pressure gradient, the more obvious the non-Darcy phenomenon. As shown in Fig. 8 and Table 3, under the same fluid viscosity condition (19.2 mPa·s), core 80-2 (permeability: 7.62×10-3μm2) has the highest permeability, and the intercept of its percolation curve on the pressure gradient axis is the minimum value 0.0401 MPa/cm. When the permeability decreases to 4.69×10-3μm2 (core 46), the intercept increases to 0.0554 MPa/cm; when the permeability decreases to 1.42×10-3μm2 (core 112), the intercept increases to 0.2847 MPa/cm; when the permeability decreases to 0.82×10-3μm2 (core 45), the intercept increases to 0.3621 MPa/cm. 3 Oil-water relative permeability curve and its influencing factors The formation of a low-permeability sandstone reservoir is a process of crude oil displacing formation water, which is characterized by oil-water two-phase migration. The oilwater relative permeability has an important influence on oil migration and accumulation, so we need determine the oil-water relative permeability and the factors influencing it for studying the formation of low-permeability sandstone reservoirs. Currently, there are many methods to measure twophase relative permeability. Among conventional unstable methods, the JBN analysis method (Johnson et al, 1959) , based on Darcy’s Law, is the most widely used. However, for low-permeability sandstones, the percolation of fluid shows non-Darcy characteristics and there is a threshold pressure gradient, so the JBN method is obviously not applicable. Based on the low-permeability non-Darcy percolation theory, previous researchers derived calculation formulae of oil-water relative permeability in consideration of threshold pressure gradient, and studied the characteristics and influencing factors of oil-water relative permeability curves of lowpermeability oil reservoirs under oil exploitation conditions (Zhang and Yin, 1999; Song and Liu, 2000; Lin and Shi, 2000; Deng et al, 2000; Jia et al, 2001; Cui et al, 2003; Wang et al, 2004; Ran et al, 2006; Dong et al, 2007; Luo et al, 2007; Hou et al, 2008) . According to the calculation method of two-phase relative permeability during the production from low-permeability reservoir (water displacing oil) presented by Song and Liu (2000) , we studied the oil-water relative permeability curve and its influencing factors in the process of reservoir formation (oil displacing water) through simulation experiments to better understand the characteristics of oil migration and accumulation in low-permeability sandstone. On the contrary to the oil production process (water displacing oil), the reservoir formation process could be viewed as the migration and accumulation of oil in the reservoir, namely a process of oil displacing formation water. Therefore its oil-water relative permeability curve is obviously different from that of the oil development process (water displacing oil). The results of our simulation experiments show that the oil-water relative permeability curve of lowpermeability sandstone has unique characteristics. Commonflow region is the area where the relative permeability of both water and oil are not equal to zero in the oil-water relative permeability curve. Common-flow point is the point at which the relative permeability of water and oil are equal, and is the intersection point of oil and water relative permeability curves (Fig. 11-Fig. 13 and Table 4). 1) When the oil saturation rises, the water-phase relative permeability drops rapidly but the oil-phase relative permeability rises a little to a low value. The area where both oil and water flow is small, and the final oil saturation is low. 2) The water-phase relative permeability curve varies a lot in shape, including concave-up (Fig. 11), “S” shape (Fig. 12), and wavy (Fig. 13), which reflects the interactions between different fluids, those on phase interfaces between fluid and solid, and the variability and complexity of percolation states. 3) Core permeability has important influence on the oilwater relative permeability. The higher the core permeability, the larger the region in which both oil and water flow. Thus, the common-flow point moves to the right, and both final oilphase permeability and final oil saturation are high (Fig. 14). 4) The fluid viscosity also affects the oil-water relative permeability. The higher the fluid viscosity, the smaller the region where both oil and water flow. Thus, the common-flow point moves to the left, and both final oil-phase permeability and final oil saturation are low (Fig. 15). 5) The combined action of physical properties of the core and fluid viscosity (apparent fluidity) affect the relative permeability. The higher the apparent fluidity, the larger the 40 50 60 Oil saturation, % 70 80 Fig. 11 Oil-water relative permeability of core 75 40 50 60 Oil saturation, % 70 80 70 80 area where both oil and water flow. Thus, the common-flow point moves to the right, and both final oil-phase permeability and final oil saturation are high (Fig. 16). 6) The driving force of injection also has an important influence on the relative permeability curve, as shown in Fig. 17. The relative permeability curves of the same core with two different pressure gradients are put in one coordinate Krw Kro system. The larger the driving pressure gradient, the larger the decrease of the water-phase relative permeability and the larger the increase of oil-phase relative permeability. Thus, the common-flow point moves to the right, and both final oilphase permeability and final oil saturation are high. Core: 75 Core: 79-2 Core: 124 Core: 97 Viscosity 19.2 19.2 7.2 7.2 40 50 60 Oil saturation, % 70 80 4 Oil saturation and the factors influencing it The processes of hydrocarbon accumulation and reservoir formation can be represented as the processes of oil displacing formation water and continuous increase of oil saturation in the reservoir under geological conditions. 4.1 Oil saturation and its increasing process A lot of previous research indicates that low permeability hydrocarbon reservoirs are generally characterized by low oil saturation (mostly<60%) and high water saturation (generally 30%-70%) (Williams et al, 1998; Law and Curtis, 2002; Ayers, 2002; Pang et al, 2002; Yang et al, 2003; Zhao et al, 2004; Wu et al, 2007) . Results of our simulation experiments indicate that under the condition of maximum displacement pressure in the laboratory, the oil saturation of low-permeability sandstone is mostly in a range of 35%-60% (Fig. 18), basically consistent segment, the longer the extension of the non-linear segment, and the smaller the curvature. The bigger the intercept of the linear segment on the pressure gradient axis, the higher the threshold pressure gradient, and the more obvious the non-Darcy phenomenon. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics; while when the apparent fluidity is less than 1.0, the percolation curve shows concave-up non-Darcy percolation characteristics. 4) For the oil-water relative permeability curve, when the oil saturation rises, the water-phase relative permeability drops rapidly but the oil-phase relative permeability rises a little to a low value. The region where both oil and water flow is small, and the final oil saturation is low. The core permeability, fluid viscosity, apparent fluidity, and injection drive force affect the oil-water relative permeability significantly. The higher the core permeability, the larger the decrease of water-phase relative permeability and the increase of oil-phase relative permeability. Thus, the oil-water common-flow region becomes larger, and the common-flow point moves to the right. Both final oil-phase permeability and final oil saturation are high. The influencing factors of apparent fluidity and driving pressure gradient are similar to those of core permeability. 5) The oil saturation of low-permeability hydrocarbon reservoirs is mostly within the range of 35%-60%, and the growth of oil saturation undergoes three stages: rapid growth stage, slow growth stage, and stable stage. 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Jianhui Zeng, Shiwei Cheng, Xu Kong, Kai Guo, Hongyu Wang. Non-Darcy flow in oil accumulation (oil displacing water) and relative permeability and oil saturation characteristics of low-permeability sandstones, Petroleum Science, 2010, 20-30, DOI: 10.1007/s12182-010-0003-2