Quantitatively study on imbibition of fracturing fluid in tight sandstone reservoir under high temperature and high pressure based on NMR technology

Abstract

Reservoir fracturing is one of the main technical means to realize high-efficiency development of low-permeability tight reservoirs in oil fields. With the implementation of reservoir fracturing measures, the imbibition effect is produced after the interaction between fracturing fluid and rocks in oil reservoirs. It is of great guiding significance to study the imbibition mechanism of fracturing fluid and quantitatively evaluate the imbibition effect of fracturing fluid with different pore throats under different conditions for practical development. In this paper, to reveal the mechanism of fracturing fluid imbibition from a microscopic point of view, based on the simulation of high temperature and high-pressure reservoir environment, using nuclear magnetic resonance (NMR) technology and dynamic physical simulation experiments, we quantitatively evaluated the imbibition effect of fracturing fluid with different pore throats at different times and investigated the influence of permeability, wettability, and viscosity of fracturing fluid on imbibition effect of fracturing fluid. The results show that the scale of imbibition of fracturing fluid is between 0.10 ms–51.20 ms. Additionally, the imbibition rate is the fastest in the initial stage of imbibition. Furthermore, the imbibition takes place in micropores (0.10 ms–1.00 ms) first, and then enters mesopores (1.00 ms–10.00 ms), followed by macropores (>10.00 ms) as the reaction time goes on. Also, micropores (0.10 ms–1.00 ms) are the best contributors to the imbibition effect of fracturing fluid, and the imbibition effect tends to be stable at first, followed by mesopores (1.00 ms–10 ms), with the highest contribution, but its imbibition effect is relatively lagging. Last, the imbibition efficiency is positively correlated with permeability, negatively correlated with fracturing fluid viscosity. It is also related to wettability. The imbibition effect of hydrophilic type is better than that of oleophilic type. The more hydrophilic the rock is, the better the imbibition effect is, and the imbibition stability time of the hydrophilic type lags behind that of the oleophilic type.