Total Gas-in-Place Estimation Using Dielectric and NMR Logging
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Solution Overview
Problem
Conventional methods for shale gas reservoir characterization face challenges due to the tight and multiscale nature of shale samples, leading to uncertainties in petrophysical properties, fluid distribution, and transport mechanisms, particularly due to the complexity of mineral content and wide range of pore sizes.
Innovation Solution
The method involves determining the mineralogy composition using spectroscopy, calculating dry permittivity, and applying a volumetric mixing law to estimate effective matrix permittivity, combining dielectric dispersion measurements with NMR T2 data to estimate water saturation and total porosity, and subsequently calculating the total gas-in-place.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If conventional sampling and measurement methods are used, then the process is simple, but the measurement precision is insufficient due to tight and multiscale nature of shale samples
Solution Approach 1:
The patent replaces conventional mechanical sampling and laboratory measurement methods with nuclear magnetic resonance (NMR) logging and dielectric dispersion measurements. These non-mechanical, non-invasive measurement techniques can directly characterize the tight and multiscale pore structures in shale formations without requiring physical core samples, thereby improving measurement precision while avoiding the limitations of conventional mechanical approaches.
Solution Approach 2:
The patent utilizes changes in NMR relaxation time parameters (T2 distributions) and dielectric dispersion parameters across different frequencies to characterize pore size distributions. By measuring these parameters at multiple conditions (different echo spacings for NMR, multiple frequencies for dielectric measurements), the system can resolve the complex multiscale pore structure and improve measurement precision for petrophysical properties.
2Reliability
If simple dielectric models are used, then the calculation is straightforward, but the reliability is reduced due to inability to account for micro-geometry and electrochemical interactions
Solution Approach 1:
The patent applies local quality by incorporating mineral-specific dielectric properties into the mixing model. Instead of using a single bulk dielectric constant, the system determines the dielectric constant for each mineral phase (quartz, feldspar, clay, carbonate, organic matter) present in the shale formation and applies them locally according to their spatial distribution and volume fractions, thereby improving reliability while accounting for the heterogeneous mineral composition.
Solution Approach 2:
The patent treats the shale formation as a composite material consisting of multiple mineral phases with different dielectric properties. By using a dielectric mixing model that combines the dielectric constants of individual minerals with their respective volume fractions and spatial arrangements, the system accurately predicts the bulk dielectric response of the formation, improving reliability for water saturation and porosity calculations.
3Measurement precision
If conventional NMR measurements with standard echo spacings are used, then the measurement is simple, but the measurement precision is insufficient for detecting small pores in multimodal distribution
Solution Approach 1:
The patent employs periodic action by acquiring NMR measurements at multiple different echo spacings (short, medium, and long echo times). This periodic variation in measurement parameters allows the system to resolve the multimodal pore size distribution by analyzing the decay characteristics at different time scales, improving measurement precision for detecting both small and large pores while capturing the full pore size spectrum.
4Productivity
If laboratory measurements on core samples are used, then the sample preparation is simple, but the productivity is reduced due to tight and multiscale nature requiring complex characterization
Solution Approach 1:
The patent replaces mechanical core sampling, cutting, mounting, and laboratory measurement procedures with downhole NMR and dielectric logging tools. This substitution eliminates the time-consuming and complex laboratory preparation process while providing in-situ measurements of pore size distribution, water saturation, and other petrophysical properties directly in the formation, thereby significantly improving productivity.
Solution Approach 2:
The patent employs a multi-functional logging system that simultaneously performs NMR measurements, dielectric dispersion measurements, and mineralogy identification in a single downhole pass. This universal approach allows the system to characterize multiple aspects of the shale formation (pore structure, fluid saturation, mineral composition) without requiring separate laboratory analyses, improving overall productivity while managing system complexity through integrated measurements.
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 provides accurate estimation of total gas-in-place by enhancing the interpretation of dielectric dispersion and NMR measurements, accounting for the diversity of minerals in shale rocks, thereby improving the accuracy of petrophysical property calculations.
Implementation Method 1
A mineralogy composition of a formation of interest is determined on core samples or downhole formation using spectroscopy measurements
Implementation Method 2
Dielectric dispersion measurements of the subject formation are acquired on the core samples using the dielectric spectrometer or across the formation of interest using the downhole measurements
Implementation Method 3
Nuclear magnetic resonance (NMR) T2 measurements having short echo spacings are acquired
Data Source
AI summary
A mineralogy composition of a formation of interest is determined using core samples or downhole measurements. A dry permittivity is determined for each identified mineral. A volumetric mixing law is employed using the determined mineralogy composition and the determined dry permitivities. An effective matrix permittivity is determined using results from the volumetric mixing law. Dielectric dispersion measurements of the subject formation are acquired using the core samples or the downhole measurements. A dielectric petrophysical model is produced using the dielectric dispersion measurements and the effective matrix permittivity. A water saturation is estimated based on the dielectric petrophysical model. Nuclear magnetic resonance (NMR) T2 measurements having short echo spacings are acquired. A NMR petrophysical model is generated based on the NMR T2 measurements. A total porosity is determined based on the generated NMR petrophysical model. A total gas-in-place estimate is made using the determined total porosity and the estimated water saturation.