Validation of model predictions of pore-scale fluid distributions during two-phase flow

Abstract

Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.

Pore Network Model Predictions of Darcy‐Scale Multiphase Flow Heterogeneity Validated by Experiments

“…The pore network model simulations were run using the approach of Valvatne and Blunt (2004) with the updated algorithm (PNflow) described in Raeini, Bijeljic, and Blunt (2018) and further validated by Bultreys et al (2018) and Raeini et al (2019). This model relies on an assumption of quasi-static capillary dominated flow.…”

Minimal surfaces in porous media: Pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone

“…Furthermore, from estimations of interfacial curvature, capillary pressure can be found [17] simultaneously with relative permeability [20], which is challenging to achieve with conventional methods. Last, the images themselves provide insight into displacement processes, can be used to correct for the capillary end effect [20], and provide benchmark data to test and validate pore-scale models [27].…”

Validating the Generalized Pore Network Model Using Micro-CT Images of Two-Phase Flow

“…Field-scale observations and experimental measurements at smaller scales provide a significant insight into the physical processes on their own (Andrew et al 2014;Berg et al 2016;Bultreys et al 2016;Gao et al 2017;Pak et al 2015;Lin et al 2017;Roman et al 2016;Rücker et al 2019;Singh et al 2017). However, in most cases the full picture can only be revealed by using mathematical/computational models to reproduce these observations (Akai et al 2019;Berg et al 2016;Bultreys et al 2018). Another challenge in field observations and experimental measurements is that they are often costly and time-consuming.…”

“…Therefore, a prediction of upscaled properties for few particular rock types is not sufficient for examining the reliability of pore network models (Bondino et al 2013;Idowu et al 2013) and validations using richer datasets are needed. Pore-by-pore validations of the network models, using direct simulations (Raeini et al 2018;Varloteaux et al 2013), multidimensional experimental data obtained from micro-CT imaging (Bultreys et al 2018) or micro-model studies (Yang et al 2017), can be considered as major steps towards reliable models of two-phase flow through porous media.…”