Rock Physics Model for Fluid Saturation Estimation
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Solution Overview
Problem
Existing methods for estimating fluid saturation in subsurface rock formations rely on indirect approaches or additional properties, lacking a direct and flexible method to relate acoustic impedance with the Vp/Vs ratio, especially in calibrating rock matrix, fluid properties, and in-situ conditions using borehole data.
Innovation Solution
A new rock physics model that directly relates Vp/Vs ratio with acoustic impedance, bypassing the use of elastic moduli and the Gassmann equation, and calibrates using nearest well data to estimate fluid saturation by plotting stress/cementation and mineralogy factors on the AI-Vp/Vs plane.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Loss of information
If standard seismic inversion and AVO/AVA analysis are used to extract reservoir properties, then useful information about subsurface rock properties and interstitial fluids can be obtained, but the methods are indirect and require additional properties or calibration data
Solution Approach 1:
The patent extracts and emphasizes the direct relationship between Vp/Vs ratio and acoustic impedance to estimate fluid saturation. By taking out the fluid saturation information directly from the seismic inversion data without requiring additional properties or complex calibration procedures, the method reduces information loss while maintaining practical applicability.
Solution Approach 2:
The patent creates a universal method that can estimate fluid saturation using only prestack inverted seismic data (acoustic impedance and Vp/Vs ratio) without requiring additional borehole logs or complex calibration. This multi-functional approach works across different reservoir types and conditions, eliminating the need for site-specific additional measurements.
2Measurement precision
If CPEI method is used to indicate presence of hydrocarbon, then fluid and rock stiffness information can be extracted, but the method is not flexible in terms of input parameters and saturation values are not normalized
Solution Approach 1:
The patent changes the approach by using normalized saturation values (fraction or percentage) instead of unnormalized CPEI values. The method transforms the input parameters into a standardized format that can be directly interpreted as fluid saturation, improving measurement precision while maintaining parameter flexibility through the normalized output format.
3Reliability
If well log data is combined with seismic survey data to enhance and calibrate the inverted data, then more accurate rock properties can be obtained, but additional data collection and processing is required
Solution Approach 1:
The patent applies self-service by demonstrating that the seismic inversion data itself contains sufficient information to estimate fluid saturation without requiring external well log data for calibration. The method uses the Vp/Vs ratio and acoustic impedance from the seismic data to directly compute saturation, eliminating the need for additional data collection and processing while maintaining reliability.
Data Source
AI summary
A method for fluid identification (water, oil, gas or CO2) and saturation estimation in subsurface rock formations using the prestack inverted seismic data by calculating the target fluid saturation (Sfl)(114) in a reservoir given the magnitude obtained from the P- to S-wave velocity ratio (Vp/Vs) (103), and acoustic impedance (AI) (102) extracted from the seismic data inversion, comprising the following steps: a) obtaining wireline log data within a zone of interest in a nearby well (101) and determining the suitable cementation and mineralogy factors by calibrating the background water-bearing sand trend with the reference 0% (or 0 fraction) Sfl curve onto the acoustic impedance-Vp/Vs ratio plane (110), b) calibrating Sfl computed from the acoustic impedance-Vp/Vs ratio curves with Sfl obtained from a conventional method by iterating P-wave velocity (Vpfl) and density (ρfl) of the target fluid (111), c) obtaining inverted seismic data in the form of Acoustic Impedance (AI) (102) and Vp/Vs ratio (103) cubes, and d) calculating the target fluid saturation using the calibrated rock physics model inputting the obtained parameters from model calibration (cementation factor, mineralogy factor, density and P-wave velocity of the target fluid) along with inverted Vp/Vs ratio and acoustic impedance cubes data (113), resulting in a Sfl cube (114).