EVALUATION OF RELATIVE PERMEABILITY OF A TIGHT OIL FORMATION
Relative permeability is one of the most important petrophysical parameters to evaluate a reservoir’s production during primary and subsequent secondary or enhanced oil recovery processes. Yet measured relative permeability data for tight oil reservoirs are very scarce to find in the literature, mainly because the measurement is difficult and time consuming to make. In this paper, the protocol and results of water/oil, surfactant/oil, CO2/oil, and N2/oil relative permeability were presented and compared to the digital core analysis results where wettability was set to 100% water-wet, as well as the Brooks-Corey model. The Amott-Harvey wettability index was measured to explain the differences. FY formation is a sandstone tight oil formation located in Daqing, China. Its permeability is mostly in the 0.01- to 5-md range. Core and oil samples from the target formation were used in the wettability and relative permeability determination. Relative permeability was measured at reservoir conditions using a customized core flow setup. Core samples were cleaned and then wettability restored. To match the reservoir fluid viscosity and avoid changing wettability, stock tank oil was blended with kerosene to reservoir fluid viscosity at reservoir temperature. Relative permeability was measured using the unsteady-state method. The Amott-Harvey wettability index was measured on core samples from the same formation at reservoir temperature. Results show that the restored wettability ranged from water-wet to weakly oil-wet. The addition of non-ionic or anionic surfactants promoted wettability change toward more water-wetness (increasing A-H index). Relative permeability results obtained from the digital rock analysis (DRA) assuming uniform water-wetness in the core sample are consistent with relative permeability calculated from mercury injection capillary pressure using the Brooks-Corey model; measured Kro is lower than DRA results indicating less water-wetness, which is consistent with the wettability measurements. The addition of surfactants increased both water and oil relative permeability through wettability alteration and IFT reduction. CO2 flood was conducted as an immiscible flood due to reservoir pressure lower than MMP. CO2 floods left high residual oil saturation compared with waterfloods. N2 floods left even more oil behind compared with CO2 floods. Relative permeability provides key input parameters for formation evaluation and the subsequent enhanced oil recovery (EOR) processes such as huff-n-puff operations. There are very few published relative permeability data for tight oil reservoirs. This work extends the relative permeability database and is a starting point for future EOR work.
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Author(s):
D. Leslie Zhang, Chunyan Qi, Xiaodong Shi, Jianfei Zhan, Xue Han, Xiangyun Li, Beijing Huamei Centur
Company(s):
CNPC USA Corp., Beijing Huamei Century International Technology Co., Exploration and Development Res
Year:
2021