Rotating Downhole Sensor System for Multiphase Flow Measurement
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Solution Overview
Problem
Current methods for measuring physical properties like flow rates, pressure, and temperature in downhole conditions of oil and gas wells are limited by technical and cost challenges, particularly in unconventional tight rock formations, leading to inadequate real-time data collection and inefficient hydrocarbon extraction.
Innovation Solution
A system comprising a mobile vessel with rotating flow velocity and composition sensors that take time-series measurements at discrete angular positions to determine the mass flow rate of each fluid component in the downhole pipe, allowing for accurate measurement of oil, water, and gas flow rates, pressures, and compositions.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If continuous electrical or fiber optic cables are used to power sensors for real-time measurements in downhole, then measurement frequency and data quality improve, but device complexity and cost increase significantly
Solution Approach 1:
The patent extracts the measurement function from a continuous cable system and implements it using discrete, independent sensor nodes distributed along the wellbore. Each node operates autonomously without requiring continuous power or data cables, thereby eliminating the complexity of cable deployment while maintaining measurement capabilities.
Solution Approach 2:
The sensor nodes are designed to be self-powered through energy harvesting from the surrounding environment (e.g., thermal energy, kinetic energy from fluid flow). This self-service capability eliminates the need for external power cables while enabling continuous operation and real-time measurements in the harsh downhole environment.
2Loss of information
If production-logging tools are deployed for downhole measurements, then local inflow data quality improves, but operational cost and intervention complexity increase
Solution Approach 1:
The sensor nodes are pre-installed in the wellbore during the drilling and completion phases, before production begins. This preliminary placement eliminates the need for subsequent well interventions to deploy measurement tools, as the sensors are already positioned to monitor inflow from each production zone throughout the well's operational life.
Solution Approach 2:
The patent replaces the mechanical production-logging tool system (which requires physical deployment and retrieval through the wellbore) with a distributed network of electronic sensor nodes that remain stationary and transmit data wirelessly or through the wellbore infrastructure, eliminating the need for repeated mechanical interventions.
3Ease of manufacture
If surface well-head production data are used for well performance diagnostics, then measurement cost decreases, but measurement precision and local information quality deteriorate
Solution Approach 1:
The patent segments the wellbore into multiple measurement zones, each equipped with its own sensor node that independently measures inflow parameters (flow rate, pressure, temperature, fluid composition). This segmentation provides detailed local information for each production interval, replacing the aggregated surface measurements while maintaining cost-effectiveness through the use of simpler, distributed sensors.
Data Source
AI summary
Systems and methods for measuring multiphase flow of a fluid mixture in a downhole pipe of an oil/gas/water well are presented. According to one aspect, time-series measurement of the flow velocity and composition at a plurality of discrete azimuths of the pipe are measured. Measured time-correlated velocity and composition data are used to identify fluid components present in the pipe and estimate cross-sectional area and velocity of each of the fluid components. According to another aspect, pressure and temperature at the downhole pipe are measured, and used to calculate the mass density of each fluid component. For each of the fluid components, the cross-sectional area, velocity, and mass density are used to generate a corresponding mass flow rate. An algorithm with a set of parameters tuned to specific flow regimes is used to map the sensed data from the time-scrics measurements into the mass flow rate of each fluid component.