Automated Upscaling Relative Permeability Multi-Porosity Reservoirs
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Solution Overview
Problem
Conventional upscaling techniques fail to accurately model fluid displacement in multi-porosity reservoirs due to simplification of rock-types as uniformly connected, leading to inaccurate simulation of subsurface fluid transfer and hydraulic properties.
Innovation Solution
The use of a 3D reservoir simulator for automated upscaling of relative permeability in multi-porosity systems, creating a single porosity-type representation by modeling fluid exchange between disparate rock-types, incorporating relative permeability, absolute permeability, and capillary pressure to simulate fluid transport and improve full-field analysis.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Device complexity
If conventional upscaling techniques assume uniform connectivity of rock-types, then the complexity of subsurface fluid transfer analysis is reduced, but the accuracy of fluid displacement modeling deteriorates
Solution Approach 1:
The patent segments the porous media into multiple discrete rock-types with distinct porosity characteristics, rather than treating all rock-types as uniformly connected. This segmentation allows each rock-type to be modeled with its specific hydraulic properties while maintaining overall system complexity manageability through systematic upscaling procedures.
Solution Approach 2:
The patent applies local quality by assigning different porosity types and connectivity characteristics to different rock-types based on their local geological properties. Each rock-type region is characterized by its specific multi-porosity parameters, allowing accurate representation of spatially varying fluid transfer behavior without requiring uniform assumptions across the entire reservoir.
2Measurement precision
If multi-porosity properties of multiple rock-types are incorporated into simulation models, then the accuracy of porous media simulation is improved, but the difficulty of subsurface fluid transfer analysis increases
Solution Approach 1:
The patent performs preliminary upscaling calculations to determine effective hydraulic properties and relative permeability parameters for each rock-type before conducting the main fluid transfer analysis. This preliminary characterization of multi-porosity properties allows the subsequent simulation to proceed with reduced complexity, as the difficult upscaling computations are completed in advance.
Solution Approach 2:
The patent introduces an intermediary upscaling procedure that translates fine-scale multi-porosity properties into coarse-scale effective parameters. This intermediary step acts as a bridge between the detailed rock-type characteristics and the reservoir-scale simulation, reducing the difficulty of direct analysis while preserving accuracy through systematic parameter transformation.
3Productivity
If conventional upscaling methods are used for multi-porosity systems, then the computational simplicity is maintained, but the accuracy of relative permeability and capillary pressure representation deteriorates
Solution Approach 1:
The patent changes the parameters being upscaled from simple hydraulic conductivity to include relative permeability and capillary pressure curves specific to each porosity type. By transforming these additional parameters into the upscaling framework, the method maintains computational efficiency while significantly improving the accuracy of multiphase fluid representation in multi-porosity systems.
Solution Approach 2:
The patent treats the multi-porosity system as a composite material with distinct phases (different porosity types) that each contribute differently to fluid flow. This composite approach allows the systematic integration of multiple rock-type properties into unified relative permeability and capillary pressure representations, achieving both accuracy and computational tractability through structured composition modeling.
Applied Scientific Principles
This section explains which scientific principles are used to turn an abstract innovation direction into a practical engineering solution.
Function Achieved in This Case
This approach enhances the accuracy of fluid exchange modeling, reduces computation time, and improves operational decision-making by considering porosity types and fluid communication between rock-types, leading to more precise simulation of core properties and reservoir management.
Implementation Method 1
automated upscaling of relative permeability in multi-porosity systems
Implementation Method 2
incorporating relative permeability, absolute permeability, and capillary pressure to simulate fluid transport
Implementation Method 3
calculating an absolute permeability and a relative permeability for the fine-scale single-porosity simulation model
Data Source
AI summary
A three-dimensional reservoir simulator used for automated upscaling relative permeability and capillary pressure in multi-porosity systems comprising disparate rock-types. A coarse-scale single-porosity model incorporating multi-porosity model properties may be derived from a fine-scale single-porosity model based, at least in part, on simulation of a model comprising data from one or more regions of interest. Real-world and laboratory measurements of the one or more regions of interest may be provided to the fine-scale single-porosity simulation model and the fine-scale single-porosity model may be subjected to one or more fractional flow simulation processes and one or more displacement simulation processes. The fine-scale model properties may be modified based, at least in part, on the results of the one or more fractional flow simulation processes and one or more displacement simulation processes. Coarse scale-model properties may be derived from the fine-scale single-porosity model properties by upscaling the fine-scale single-porosity model. The coarse-scale single-porosity simulation model incorporating multi-porosity model properties may be used to improve operational decision-making, including drilling operations and reservoir management.