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Dynamic coupling of pore‐scale and reservoir‐scale models for multiphase flow
Author(s) -
Sheng Qiang,
Thompson Karsten
Publication year - 2013
Publication title -
water resources research
Language(s) - English
Resource type - Journals
SCImago Journal Rank - 1.863
H-Index - 217
eISSN - 1944-7973
pISSN - 0043-1397
DOI - 10.1002/wrcr.20430
Subject(s) - mechanics , multiphase flow , relative permeability , capillary pressure , reservoir simulation , boundary value problem , network model , saturation (graph theory) , permeability (electromagnetism) , scale (ratio) , state variable , coupling (piping) , scale model , flow (mathematics) , statistical physics , simulation , computer science , porous medium , mathematics , geotechnical engineering , engineering , porosity , physics , petroleum engineering , thermodynamics , chemistry , mechanical engineering , quantum mechanics , database , membrane , aerospace engineering , mathematical analysis , biochemistry , combinatorics
The concept of coupling pore‐scale and continuum‐scale models for subsurface flow has long been viewed as beneficial, but implementation has been slow. In this paper, we present an algorithm for direct coupling of a dynamic pore‐network model for multiphase flow with a traditional continuum‐scale simulator. The ability to run the two models concurrently (exchanging parameters and boundary conditions in real numerical time) is made possible by a new dynamic pore‐network model that allows simultaneous injection of immiscible fluids under either transient‐state or steady‐state conditions. Allowing the pore‐scale model to evolve to steady state during each time step provides a unique method for reconciling the dramatically different time and length scales across the coupled models. The model is implemented by embedding networks in selected gridblocks in the reservoir model. The network model predicts continuum‐scale parameters such as relative permeability or average capillary pressure from first principles, which are used in the continuum model. In turn, the continuum reservoir simulator provides boundary conditions from the current time step back to the network model to complete the coupling process. The model is tested for variable‐rate immiscible displacements under conditions in which relative permeability depends on flow rate, thus demonstrating a situation that cannot be modeled using a traditional approach. The paper discusses numerical challenges with this approach, including the fact that there is not a way to explicitly force pore‐scale phase saturation to equal the continuum saturation in the host gridblock without an artificial constraint. Hurdles to implementing this type of modeling in practice are also discussed.