Downhole Fluid Sampling Phase Identification
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Solution Overview
Problem
Conventional downhole fluid sampling methods face challenges in accurately determining fluid properties of multi-phase formation fluids due to contamination from drilling fluids, leading to non-representative samples and unreliable contamination estimation.
Innovation Solution
A downhole fluid sampling tool equipped with sensors that measure and cluster channel data to identify specific phases of multi-phase fluids, allowing for accurate fluid labeling and property estimation, using optical and non-optical sensors to differentiate between phases and determine fluid ratios and signatures.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Reliability
If conventional downhole fluid sampling methods are used, then fluid samples can be obtained from the reservoir, but the samples become contaminated with drilling fluids and lose representativeness
Solution Approach 1:
The patent segments the fluid sampling process into distinct phases: initial contamination phase, transition phase, and clean formation fluid phase. By identifying and analyzing the transition phase where fluid properties change over time, the system can distinguish between drilling fluid contamination and formation fluid, thereby obtaining representative formation fluid samples while accounting for contamination effects.
Solution Approach 2:
The system performs preliminary measurements of fluid properties (density, GOR, resistivity) during the contamination phase before clean formation fluid is obtained. These preliminary data points establish a baseline contamination signature that is used to correct subsequent measurements and estimate contamination levels, improving the reliability of all samples obtained during the operation.
2Measurement precision
If downhole fluid analysis is performed, then real-time fluid properties can be obtained, but accurate determination of single-phase properties becomes problematic in multi-phase conditions
Solution Approach 1:
The patent introduces a temporal dimension to the fluid analysis by measuring fluid properties continuously over time during the pump-out operation. This time-based approach allows the system to observe how fluid properties evolve as contamination is displaced, enabling differentiation between single-phase and multi-phase conditions and accurate determination of formation fluid properties even in multi-phase environments.
Solution Approach 2:
The system uses real-time feedback from dynamic measurements of density, gas-to-oil ratio, and resistivity to identify phase transitions and contamination levels. This feedback mechanism allows the system to adjust its analysis approach based on current fluid conditions, accurately determining properties of individual phases by recognizing when the fluid stream transitions from mixed phases to single-phase formation fluid.
3Loss of information
If dynamic measurement of subsurface optical spectra is used, then phase identification can be achieved on different optical channels, but fluid ratio estimation and signature extraction become complex without proper phase identification
Solution Approach 1:
The patent employs dynamic optical spectroscopy measurements that capture changes in fluid composition over time. By analyzing the temporal dynamics of optical spectra across multiple channels, the system can identify characteristic absorption features of different fluid phases (oil, water, gas) and separate their signals. This dynamic approach simplifies phase identification compared to static analysis, as the evolving spectral signatures provide clear indicators of phase composition and ratios.
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 enables precise identification of fluid phases and contamination levels, improving the accuracy of fluid ratio estimation and signature extraction, thereby enhancing the reliability of downhole sampling operations and reservoir evaluation.
Implementation Method 1
dynamic measurement of subsurface optical spectra may meet one phase on some optical channels, and another phase on some other optical channels
Data Source
AI summary
A method and a system for measuring downhole fluid properties. The downhole fluid sampling tool may comprise at least one probe and at least one passageway that passes through the at least one probe and into the downhole sampling tool. The method may comprise drawing a wellbore fluid through the at least one probe and through the at least one passageway, obtaining a first channel measurement of the wellbore fluid, obtaining at least a second channel measurement, clustering channel data from a plurality of channel measurements comprising the first channel measurement and the at least second channel measurement, and measuring a phase through a plurality of channels. The method may further comprise separating a plurality of phase signals based on the phase measured through the plurality of channels, labeling the wellbore fluid, assigning the plurality of phase signals to specific phases of a multi-phase fluid, and estimating a fluid property.