Marinus Izaak Jan Van Dijke

Droplet fragmentation: 3D imaging of a previously unidentified pore-scale process during multiphase flow in porous media

Significance Fluid displacement processes in carbonate rocks are important because they host over 50% of the worlds hydrocarbon reserves and are aquifers supplying water to one quarter of the global population. A previously unidentified pore-scale fluid displacement event, droplet fragmentation, is described that occurs during the flow of two immiscible fluids specifically in carbonate rocks. The complex, heterogeneous pore structure of carbonate rocks induces this droplet fragmentation process, which explains the increased recovery of the nonwetting phase from porous carbonates as the wetting phase injection rate is increased. The previously unidentified displacement mechanism has implications for (i) enhanced oil recovery, (ii) remediation of nonaqueous liquid contaminants in aquifers, and (iii) subsurface CO2 storage. Using X-ray computed microtomography, we have visualized and quantified the in situ structure of a trapped nonwetting phase (oil) in a highly heterogeneous carbonate rock after injecting a wetting phase (brine) at low and high capillary numbers. We imaged the process of capillary desaturation in 3D and demonstrated its impacts on the trapped nonwetting phase cluster size distribution. We have identified a previously unidentified pore-scale event during capillary desaturation. This pore-scale event, described as droplet fragmentation of the nonwetting phase, occurs in larger pores. It increases volumetric production of the nonwetting phase after capillary trapping and enlarges the fluid−fluid interface, which can enhance mass transfer between the phases. Droplet fragmentation therefore has implications for a range of multiphase flow processes in natural and engineered porous media with complex heterogeneous pore spaces.

Accurate Modelling of Pore-Scale Films and Layers for Three-Phase Flow Processes in Clastic and Carbonate Rocks with Arbitrary Wettability

Three-phase flow is a key process occurring in subsurface reservoirs, for example, during

Constitutive Relations for Reactive Transport Modeling: Effects of Chemical Reactions on Multi-phase Flow Properties

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Relationship between pore-scale characteristics and petrophysical properties

sequestration and enhanced oil recovery techniques such as water alternating gas (WAG) injection. Predicting three-phase flow processes, for example, the increase in oil recovery during WAG, requires a sound understanding of the fundamental flow physics in water- to oil-wet rocks to derive physically robust flow functions, i.e. relative permeability and capillary pressure. In this study, we use pore-network modelling, a reliable and physically based simulation tool, to predict the flow functions. We have developed a new pore-scale network model for rocks with variable wettability, from water- to oil-wet. It comprises a constrained set of parameters that mimic the wetting state of a reservoir. Unlike other models, it combines three main features: (1) A novel thermodynamic criterion for formation and collapse of oil layers. The new model hence captures wetting film and layer flow of oil adequately, which affects the oil relative permeability at low oil saturation and leads to accurate prediction of residual oil. (2) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows for the accurate modelling of the mobilisation of many disconnected phase clusters that arise, in particular, during higher order WAG floods. (3) The model takes realistic 3D pore-networks extracted from pore-space reconstruction methods and CT images as input, preserving both topology and pore shape of the sample. For water-wet systems, we have validated our model with available experimental data from core floods. For oil-wet systems, we validated our network model by comparing 2D network simulations with published data from WAG floods in oil-wet micromodels. This demonstrates the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points.

3D Stochastic Modelling of Heterogeneous Porous Media – Applications to Reservoir Rocks

A multi-scale network integration approach introduced by Jiang et al. [2013] is used to generate a representative pore-network for a carbonate rock with a pore-size distribution across several orders of magnitude. We predict the macroscopic flow parameters of the rock utilising i) 3D images captured by X-ray computed micro-tomography and ii) pore-network flow simulations. To capture the multi-scale pore-size distribution of the rock we imaged four different rock samples at different resolutions and integrated the data to produce a pore-network model that combines information at several length-scales that cannot be recovered from a single tomographic image. A workflow for selection of the number and length-scale of the required input networks for the network integration process, as well as fine tuning the model parameters is presented. Mercury injection capillary-pressure data were used to evaluate independently the multi-scale networks. We explore single-scale, two-scale, and three-scale network models and discuss their representativeness by comparing simulated capillary-pressure versus saturation curves with laboratory measurements. We demonstrate that for carbonate rocks with wide pore-size distributions, it may be required to integrate networks extracted from two or three discrete tomographic data sets in order to simulate macroscopic flow parameters. This article is protected by copyright. All rights reserved.

Modelling the permeability evolution of carbonate rocks

The relationship between flow properties and chemical reactions is the key to modeling subsurface reactive transport. This study develops closed-form equations to describe the effects of mineral precipitation and dissolution on multi-phase flow properties (capillary pressure and relative permeabilities) of porous media. The model accounts for the fact that precipitation/dissolution only takes place in the water-filled part of pore space. The capillary tube concept was used to connect pore-scale changes to macroscopic hydraulic properties. Precipitation/dissolution induces changes in the pore radii of water-filled pores and consequently in the pore size distribution. The updated pore size distribution is converted back to a new capillary pressure–water saturation relation from which the new relative permeabilities are calculated. Pore network modeling is conducted on a Berea sandstone to validate the new continuum-scale relations. The pore network modeling results are satisfactorily predicted by the new closed-form equations.

Three-Phase Pore-Network Modeling for Reservoirs With Arbitrary Wettability

The wide range of pore sizes in carbonates (differences of three to five orders of magnitude) aggravates the already difficult problem of multiple minima in pore network model (PNM) parameters. In this paper, we propose a method to estimate the PNM structural parameters. We have applied the method to four cases: one synthetic case and three carbonate rock samples. The PNM structural parameter estimates were conditioned to the mercury intrusion capillary pressure (MICP) via a stochastic inversion algorithm that uses molecular dynamics combined with stochastic steps using Hamiltonian mechanics. This algorithm, Hamiltonian Monte Carlo (HMC), allows for large moves in the phase space making use of the periodicity developed due to the Hamiltonian formulation, thus large modifications in the model parameters are possible. Additionally, we introduced a new estimator of the pore-size distribution using MICP. The statistics of the stochastic inversion found the multiple local minima and the global minimum of the misfit function in a difficult case. The results for the synthetic case showed that the volume and fraction of small pores in the pore-size distribution can lead to multiple local minima. For the three carbonate rock samples, the model parameters clearly showed that the volume exponents are greater than zero, which contradicts the usual assumption and inferences made by other methods. As the pore-size distribution becomes multi-modal, the volume exponent decreases but is greater than zero. These results suggest that when microporosity is ignored the volume exponent will systematically tend to be strongly underestimated (values close to zero). Our findings demonstrate that lattice-type PNM parameter estimation is a difficult problem because of multiple minima. The HMC method was able to escape from those multiple minima, resulting in better estimates of the PNM parameters.

Prediction of Three-Phase Relative Permeabilities Using a Pore-Scale Network Model Anchored to Two-Phase Data

Fluid flow properties of geomaterials are fundamentally controlled by the characteristics of the pore system and the interaction of different fluid phases occupying complex pore shapes. Both the geometric and topological characteristics of the pore system are important, and each separately influences the flow of fluids. Here, we report a study in which we use network models to assess fluid flow through pore systems extracted from coarse-grained and fine-grained materials. Arbitrary changes to the pore systems, which mimic the effects of compaction, diagenesis, and possibly deformation, produce changes in the multi-phase flow properties, but the roles of pore size and connectivity vary in different materials. Continuing studies aim to identify predictive relationships between readily-obtainable descriptors and the hard-to-determine flow characteristics.