NMR Well Logging Fluid Velocity and Pore Size Distribution
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Solution Overview
Problem
Current wireline logging measurements in hydrocarbon exploration wells infer fluid flow properties of reservoir rock from non-flowing fluids rather than directly measuring flowing fluids, leading to uncertainties in permeability determination.
Innovation Solution
A method involving the injection of acoustic energy, generation of a magnetic field gradient, and injection of radio frequency energy into the porous medium, with measured NMR signals processed to determine fluid displacement, velocity, and pore size distribution, allowing for direct measurement of fluid flow properties.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Productivity
If wireline logging measurements are used to infer fluid flow properties from non-flowing fluids, then continuous data over large reservoir intervals can be obtained at lower cost, but measurement precision and reliability of fluid flow properties deteriorate due to indirect inference rather than direct measurement
Solution Approach 1:
The patent replaces indirect mechanical inference methods with direct physical measurement using NMR technology. Instead of inferring fluid flow properties from static measurements, the system uses nuclear magnetic resonance to directly detect fluid velocity, pore size distribution, and flow characteristics in real-time, substituting mechanical inference with quantum-based direct detection
Solution Approach 2:
The patent changes the measurement parameters from static fluid properties to dynamic flow properties by applying magnetic field gradients and measuring NMR signal phase changes. This allows direct measurement of fluid velocity and flow characteristics rather than inferring from stationary fluid parameters
2Measurement precision
If direct measurement of fluid flow properties is implemented using NMR with acoustic energy, then measurement precision and reliability improve, but device complexity and measurement cost increase
Solution Approach 1:
The patent creates a multi-functional measurement system where a single NMR-based device can measure multiple fluid flow properties including velocity, pore size distribution, permeability, and saturation simultaneously. This universal approach reduces the need for multiple separate measurement systems and core analysis procedures
Solution Approach 2:
The patent introduces acoustic energy as an intermediary to induce fluid motion and magnetic field gradients as mediators to encode velocity information into NMR signals. These intermediaries enable the direct measurement of flow properties without requiring complex mechanical sampling or laboratory analysis
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 method provides more accurate and direct measurements of fluid flow properties, reducing uncertainties and improving the assessment of reservoir economics and production planning.
Implementation Method 1
injecting acoustic energy into the portion of the porous medium
Implementation Method 2
generating a magnetic field gradient within the portion of the porous medium
Implementation Method 3
injecting a radio frequency energy into the portion of the porous medium. The acoustic energy, the magnetic field gradient, and radio frequency energy have a predetermined relationship in time
Implementation Method 4
measuring an NMR signal from the portion of the porous medium
Data Source
AI summary
A method is disclosed for the non-destructive determination of the pore size distribution and the distribution of fluid flow velocities using NMR spin echo signal measurements. In one embodiment, the invention involves simultaneously injecting acoustic energy (208), generating a magnetic field having a gradient, and injecting radio-frequency electromagnetic energy (206) into a subsurface region, using for example an NMR tool and a well logging tool having an acoustic transmitter placed in a wellbore (202). The spin echo signal generated in the subsurface region is measured (210) by the NMR tool for at least two values (212) of the magnetic field gradient. A relationship is provided by which the pore fluid velocity distribution may be calculated (214) from the inverse Fourier transform of the spin echo data. The pore size distribution may then be calculated from the pore fluid velocity distribution.