实际油藏条件下毛管力曲线测定方法

A capillary pressure measurement method at real reservoir conditions

研发高温高压毛管力曲线测定仪,使用地层水和含有溶解气的地层油,模拟油藏温度和压力条件,测定渗透率不同的3块岩心的地下毛管力曲线,并与压汞法得到的地下毛管力曲线进行对比。结果表明:由压汞毛管力曲线按照常规转换方法得到的地下毛管力曲线均比实测毛管力曲线低,两种曲线在曲线平缓段有较大差别,渗透率为(0.3~1.3)×10^(-3)μm^2的岩心,润湿相饱和度70%时毛管力差值为0.08~0.12 MPa;通过压汞毛管力曲线与实际毛管力曲线拟合,渗透率为(0.3~1.3)×10^(-3)μm^2的岩心实际转换系数为4~5(常规转换系数为7.26),渗透率越高的岩心拟合系数越低。

A high temperature and high pressure capillary pressure measurement apparatus was developed in this study, and the capillary pressure curve of rock samples with different permeability at reservoir condition was measured and compared with that converted from a mercury injection method. Live oil containing solution gas and real reservoir water were used in these measurements. The results show that the reservoir capillary pressure converted from the mercury injection method was lower than that measured using the new apparatus. There is a significant difference on the flat section of the capillary pressure curves measured by the two methods, which is about 0.08-0.12 MPa at wetting saturation of 70% for the cores with permeability of （0.3-1.3 ）× 10^-3 μm2. When the real capillary curves with those measured using the mercury injection method fit well, the ratio of the capillary pressures from the two methods （ the conversion factor） is about 4-5, lower than the conventional value of 7.26. The higher the permeability of the rock is, the lower the conversion factor.