Heated Cable Fluid Measurement System for Wellbore Composition Analysis
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Solution Overview
Problem
Current methods for measuring fluid flow rates and compositions in oil and gas wells, particularly in mixed fluid mixtures, are limited by their inability to distinguish between different fluid types and require high power consumption, leading to impracticality in long sampling lengths and high flow rates.
Innovation Solution
A fluid measurement system comprising an elongate structure with a heated core element and distributed temperature sensors, combined with high-frequency pulse generators and data acquisition units, which measures heat loss and pulse velocity to determine fluid type and flow rate in two dimensions, utilizing the varying signal velocity through different fluids to derive a two-dimensional measure of fluid type and velocity.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If a heated cable is used to measure fluid flow rate by detecting cooling effect, then flow rate measurement is achieved, but the system cannot distinguish between different fluid types (oil, water, gas) and only provides average flow rate
Solution Approach 1:
The patent combines two measurement techniques into a single integrated system: distributed temperature sensing (DTS) for flow rate measurement and high-frequency electromagnetic pulse transmission for fluid type identification. By merging these methods in one probe, the system simultaneously achieves both flow rate quantification and fluid composition discrimination without requiring separate measurement devices.
Solution Approach 2:
The measurement probe is designed to perform multiple functions: it acts as both a heated cable for thermal flow measurement and a transmission line for electromagnetic pulse propagation. This multi-functional design allows a single device to provide both velocity measurement through thermal cooling detection and fluid type identification through electromagnetic signal analysis.
2Reliability
If the wellbore temperature is elevated above surrounding fluid and formation temperature to achieve flow measurement, then flow detection is enabled, but large amounts of power are required which is impractical for long sampling lengths and high flow rates
Solution Approach 1:
Instead of heating the entire wellbore or using excessive power to elevate temperature throughout, the system applies thermal energy locally at the measurement probe and uses high-frequency electromagnetic pulses for fluid identification. The DTS method requires minimal heating power compared to traditional methods because it measures temperature differentials rather than maintaining elevated temperatures over long distances.
Solution Approach 2:
The patent replaces the mechanical/thermal heating system with an electromagnetic field-based measurement approach. High-frequency electromagnetic pulses are used to identify fluid types based on dielectric properties, eliminating the need for substantial thermal power input while maintaining reliable flow measurement capability through the DTS system.
3Measurement precision
If point sensors are used to measure fluid properties, then measurements are obtained at sensor position, but the entire wellbore cannot be monitored in real time and only periodic logging is possible
Solution Approach 1:
The measurement system is divided into multiple discrete sensing points along the wellbore, with each segment providing localized measurements. The wellbore is effectively segmented into measurement zones, allowing comprehensive coverage through distributed sensing while enabling real-time data collection from each segment simultaneously.
Solution Approach 2:
The system transitions from point-based temporal sampling to distributed spatial measurement by deploying sensors along the entire wellbore length. This dimensional expansion from single-point to multi-point spatial distribution enables simultaneous real-time monitoring of the complete wellbore, transforming periodic logging into continuous distributed measurement.
4Measurement precision
If logging tools with single sensors are used to traverse the wellbore, then measurements are obtained, but the whole wellbore is not logged in real time and tools are difficult to run when pumps are present
Solution Approach 1:
Multiple sensing functions are merged into a single integrated probe that can be deployed once to measure the entire wellbore. The probe combines DTS heating elements, temperature sensing fibers, and electromagnetic pulse transmission capabilities, eliminating the need to run multiple separate logging tools through the wellbore.
Solution Approach 2:
The measurement system is designed to be self-contained and self-sufficient, with all necessary sensing and measurement capabilities integrated into the probe itself. The system requires no external assistance or complex tool strings, making it easy to deploy and operate even in the presence of wellbore pumps or other obstructions.
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 system enables accurate, low-power measurement of fluid flow rates and compositions in mixed fluids, providing a two-dimensional or three-dimensional analysis of fluid properties, including gas content, even in high flow rates and complex fluid regimes, by using thermal isolation and probabilistic modeling to interpret chaotic signals.
Implementation Method 1
a heated core element and a distributed temperature sensor along the length of the structure, said heated core element and said distributed temperature sensor arranged so that the temperature sensor is physically between the heated core and an outside surface of the structure to sense heat loss from the core to its environment
Implementation Method 2
at least one high frequency pulse generator for injecting a high frequency pulse along the wire of at least one sampling section of the structure
Data Source
Figure 1a~1c
Figure 2
Figure 3
AI summary
A fluid measurement system and method for determining distributed measurement of a fluid type and a fluid velocity in a wellbore, pipeline or other conduit in which fluid is moving. Measurement is made by immersing one or more cables having sequential sampling sections in the fluid and monitoring a cooling effect across a cable on the sampling sections and the response to injection of a high frequency pulse each sampling section. A probabilistic model is then used to determine the distributed velocity and fluid types along the conduit.