A Measured Method for In Situ Viscosity of Fluid in Porous Media by Nuclear Magnetic Resonance

Abstract

At present, the existing measuring methods for viscosity of fluid can only obtain the viscosity of bulk fluid, while the in situ viscosity of fluid in porous media cannot be acquired. In this paper, with the combination of nuclear magnetic resonance (NMR) and physical simulation experiment, a testing method for in situ viscosity of fluid in porous media is established, and the in situ viscosity spectra of water in tight cores under different displacement conditions is obtained. The experimental results show that the in situ viscosity distribution of water in porous media is inhomogeneous, and it is not a constant but is related to the distance between water and rock walls. When the distance between fluid and rock walls is close enough (e.g., 2 relaxation time is less than 1 ms), the viscosity of fluid increases rapidly, and the in situ viscosity is greater than the bulk viscosity. Moreover, after the rock samples are saturated with water, the in situ viscosity of water is distributed as a double-peak structure. The left peak is characterized mainly by the in situ viscosity distribution of movable fluid, whose in situ viscosity is smaller, and the right peak mainly represents the in situ viscosity distribution characteristics of immovable fluid, whose in situ viscosity is larger and increases gradually. Under a relatively large driving force, the in situ viscosity amplitude of movable fluid decreases greatly, and the average in situ viscosity of residual water in the core is much higher than that of saturated water in initial state.

Application of NMR to Test Sandstone Stress Sensitivity of the Dongfang X Gas Field, China

“…Moreover, the T2 signal of rock decreases obviously under the condition of stress, which proves that we can use the loss of T2 value to characterize the stress sensitivity of the study area rock. According to the formula (3) and previous studies [21], [44], [45], [48]- [52], one can acknowledge that smaller pores have shorter relaxation time and larger pores have longer relaxation time, so the area under the left peak can be considered as the content of micropores, while the area below the right peak can be represented as the content of macropores. The difference between the area enclosed by the T2 spectrum in the initial state and that in the compressed state reflects the compression degree of the pores under a certain stress.…”

Reconstruction and Analysis of Tight Sandstone Digital Rock Combined with X-Ray CT Scanning and Multiple-Point Geostatistics Algorithm

“…It is acknowledged that the short T2 time in the T2 spectrum represents the small pore space and the long T2 time represents the big pore space [38][39][40]. We compared the results of the laboratory NMR test on the sandstone sample with the simulation NMR results on digital rocks.…”

Flow simulation considering adsorption boundary layer based on digital rock and finite element method

“…Li et al (2018) built a capillary permeability model and studied the influence of ABL on tight reservoirs. Yang et al (2018) studied the ABL in the plate space using nuclear magnetic resonance. Song et al (2019a) proposed a new single-channel flow model for describing nonlinear flow in low-permeability reservoirs based on ABL theory.…”