Rock Image Fluid Saturation Correction for Sub-Resolution Pores
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Solution Overview
Problem
Conventional digital rock physics modeling underpredicts fluid saturation due to the inability to account for sub-resolution pore volumes in micron-scale images, leading to inaccurate fluid flow simulations in hydrocarbon-containing reservoirs.
Innovation Solution
A method for estimating fluid saturation using a backpropagation-enabled process to segment 3D rock images, correcting for sub-resolution pore volumes by applying a correction factor to image-derived wetting fluid saturation, and utilizing direct flow simulations to determine corrected fluid saturation.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Productivity
If direct numerical simulation is performed on micron-scale images, then fluid flow simulation speed is improved, but measurement precision of fluid saturation deteriorates due to sub-resolution pore volumes
Solution Approach 1:
The patent introduces an intermediary correction process that bridges the gap between image-based simulations and laboratory measurements. A correction factor is calculated based on the ratio of actual pore volume to image pore volume, and this correction factor is applied to simulation results to obtain corrected fluid saturation values that align with laboratory measurements.
Solution Approach 2:
The patent changes the parameter of fluid saturation by applying a correction factor derived from pore volume ratios. The correction factor adjusts the simulation results to account for sub-resolution pore volumes, transforming the raw simulation output into corrected values that reflect actual reservoir conditions.
2Loss of time
If conventional digital rock physics modeling is used, then processing time is reduced, but manufacturing precision of fluid saturation estimation deteriorates
Solution Approach 1:
The patent performs preliminary action by calculating the correction factor before finalizing fluid saturation estimates. The correction factor is pre-computed based on pore volume ratios, allowing rapid correction of simulation results without requiring additional time-consuming simulations or laboratory measurements for each case.
3Measurement precision
If image resolution is increased to capture sub-resolution pore volumes, then measurement precision of fluid saturation is improved, but device complexity and cost increase
Solution Approach 1:
The patent creates a corrected copy of the simulation results by applying the correction factor. Instead of acquiring higher resolution images, the method copies the existing simulation output and adjusts it mathematically to reflect the true fluid saturation, avoiding the need for complex high-resolution imaging systems.
Data Source
AI summary
The present invention provides a method for estimating fluid saturation of a hydrocarbon-bearing rock from a rock image. The image is segmented to represent either a pore space or solid material in the rock. An image pore volume is estimated from the segmented image, and a corrected pore volume is determined to account for the sub-resolution pore volume missing in the image of the rock. An image-derived wetting fluid saturation of the rock is estimated using a direct flow simulation on the rock image and corrected for the corrected pore volume. A backpropagation-enabled trained model can be used to segment the image. A backpropagation-enabled method can be used to estimate the fluid saturation using an image selected from a series of 2D projection images, 3D reconstructed images and combinations thereof.