Shale Formation Modeling Kerogen Layer Segmentation
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Solution Overview
Problem
Current formation modeling tools designed for conventional reservoirs are inaccurate for predicting future hydrocarbon production from shale formations due to their vastly different permeability and layering characteristics, which complicates the selection of permeability and porosity parameters for kerogen-rich and kerogen-poor layers.
Innovation Solution
The method involves estimating kerogen-related porosity based on total organic content, vitrinite reflectivity, and burial history, and using micro-scale simulations to determine permeability, while accounting for fracture porosity and water-wet porosity to improve the accuracy of hydrocarbon production modeling in layered shale formations.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If existing formation modeling tools designed for conventional reservoirs are used for shale formations, then the modeling process is simple and familiar, but the accuracy of future production prediction is highly inaccurate
Solution Approach 1:
The shale formation is segmented into multiple layers based on kerogen content (kerogen-rich layers and kerogen-poor layers), each assigned different permeability values. This segmentation allows the model to capture the heterogeneous nature of shale formations while maintaining a structured approach to parameter assignment, resolving the contradiction between accuracy and complexity.
Solution Approach 2:
Different permeability values are assigned to different layers based on their kerogen content characteristics. Kerogen-rich layers are assigned lower permeability values while kerogen-poor layers receive higher permeability values. This local differentiation improves prediction accuracy without requiring complete reformulation of the modeling framework.
2Measurement precision
If formation models are tuned to actual production history from shale formations, then the model fits historical data, but the models are highly inaccurate as to future production from the shale formations
Solution Approach 1:
The model uses parameter changes based on kerogen content to represent future production behavior. By assigning different permeability values to kerogen-rich and kerogen-poor layers, the model captures the evolving production characteristics as different layers are depleted at different rates, improving future production prediction while maintaining reasonable historical matching.
3Measurement precision
If shale formations are modeled as homogeneous units, then the modeling process is straightforward, but the models fail to account for the vastly different permeability (500 times less) between kerogen-rich and kerogen-poor layers
Solution Approach 1:
The formation is divided into discrete layers based on kerogen content, with each layer assigned specific permeability characteristics. This segmentation approach allows the model to represent the 500-fold permeability difference between kerogen-rich and kerogen-poor layers while maintaining a manageable structural complexity through systematic layer classification.
Solution Approach 2:
Each layer is assigned local permeability quality based on its kerogen content. Kerogen-rich layers receive low permeability assignments while kerogen-poor layers receive high permeability assignments. This local quality differentiation accurately represents the physical heterogeneity without requiring overly complex modeling structures.
Data Source
AI summary
Modeling hydrocarbon flow, from layered shale formations. At least some of the illustrative embodiments are methods including: modeling movement of hydrocarbons through kerogen-related porosity, the movement through a first model volume; estimating a first permeability of a kerogen-rich layer of a layered shale formation based on the modeling; and modeling hydrocarbon production from the layered shale formation. The modeling hydrocarbon production may include: utilizing the first permeability for the kerogen-rich layer of the layered shale formation; and utilizing a second permeability for a kerogen-poor layer of the layered shale formation, the second permeability different than the first permeability. In various cases the modeling of hydrocarbon production is with respect to a second model volume greater than the first model volume.