Characterising Drainage Multiphase Flow in Heterogeneous Sandstones

Abstract

In this work, we analyse the characterisation of drainage multiphase flow properties on heterogeneous rock cores using a rich experimental dataset and mm-m scale numerical simulations. Along with routine multiphase flow properties, 3D sub-metre scale capillary pressure heterogeneity is characterised by combining experimental observations and numerical calibration, resulting in a 3D numerical model of the rock core. The uniqueness and predictive capability of the numerical models are demonstrated by accurately predicting the experimentally measured relative permeability of N 2 -DI water and CO 2 -brine systems in two distinct sandstone rock cores across multiple fractional flow regimes and total flow rates. The numerical models are used to derive equivalent relative permeabilities, which are upscaled functions incorporating the effects of sub-metre scale capillary pressure. The functions are obtained across capillary numbers which span four orders of magnitude, representative of the range of flow regimes that occur in subsurface CO 2 injection. Removal of experimental boundary artefacts allows the derivation of equivalent functions which are characteristic of the continuous subsurface. We also demonstrate how heterogeneities can be re-orientated and restructured efficiently to obtain large amounts of information about expected flow regimes through different small-scale rock structures. This analysis shows how combined experimental and numerical characterisation of rock samples can be used to derive equivalent flow properties from heterogeneous rocks.

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

“…First, traditional approaches are impacted by experimental artifacts, such as the capillary end effects, as described in detail in Figure 3. Another advantage of using PNM to characterize capillary heterogeneity is that measurements are not influenced by viscous forces that are typically ignored with assumptions of capillary equilibrium across the system (Krause et al, 2013;Pini & Benson, 2013Jackson, Agada, et al, 2018;Hejazi et al, 2019). Finally, approaches for quantifying capillary heterogeneity rely on J-Leverett scaling (Leverett, 1940;Krause et al, 2013;Pini & Benson, 2013).…”

Simulating Core Floods in Heterogeneous Sandstone and Carbonate Rocks

“…Previous work found that permeability heterogeneity is not the dominant fluid distribution mechanism at lower flow rates (Jackson et al, 2018). Furthermore, Leverett-J function scaling is invalid for rocks with a multi-modal porosity (Sarwaruddin et al, 2001).…”

“…It is well known that laboratory relative permeability measurements are strongly influenced by permeability heterogeneity within cores that arises from sedimentary structures like crossbedding in sandstones or shell fragments in carbonates (Corey & Rathjens, 1956;Huppler, 1970;Kortekaas, 1985;Hove et al, 1990;Hamon & Roy, 2000;Dawe et al, 1992;Chang & Yortsos, 1992). The impact of porosity and capillary heterogeneity is less well understood although recent research indicates that it is one of the leading causes of anisotropy and flow rate dependency in observed relative permeability and thus can have a significant impact on upscaled properties (Krishnamurthy et al, 2017(Krishnamurthy et al, , 2019Jackson et al, 2018;Boon & Benson, 2021;Ershadnia et al, 2021).…”

“…The workflow uses a numerical history match of a coreflood experiment with the 3D saturation distribution as a matching target and the 3D capillary pressure characteristics as well as the absolute permeability distribution as a fitting parameter. In recent years, the approach has been further applied to a wide range of samples and developed to improve the observational basis and strengthen the iterative matching procedure (Berg et al, 2013;Krause et al, 2013;Pini & Benson, 2013a, 2013bKong et al, 2015;Krause & Benson, 2015;Jackson et al, 2018;Reynolds et al, 2018;Hosseinzadeh Hejazi et al, 2019;Ni et al, 2019). However, uncertainty still remains in characterising more complex rocks typical of subsurface reservoirs across multiple fractional flows and flow rates, e.g.…”

“…In this work we evaluate the approach described by Jackson et al (2018) to characterise heterogeneity in rock cores across five rock samples selected for their range of heterogeneity types and length scales comprising two sandstones and three carbonates.…”