Subsea Flow Rate Estimation Using Statistical Sensor Fusion
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Solution Overview
Problem
The high cost and complexity of conventional subsea instrumentation for measuring fluid flow rates from subsea oil and gas wells hinder the development of hydrocarbon fields, as they require extensive and expensive sensor systems for accurate multi-phase flow rate estimation.
Innovation Solution
A method and apparatus that estimate gas, water, and oil flow rates from subsea wells in real-time by integrating discrete measurements from distributed sensors around the completion and production tree, using a statistical estimator unit with inputs from pressure, temperature, and flow rate sensors, reducing the need for complex and costly subsea instrumentation.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If conventional subsea instrumentation (MPFM, WFGM) is used to measure multi-phase flow rates, then measurement accuracy is improved, but capital cost and device complexity increase significantly
Solution Approach 1:
The invention divides the flow measurement system into separate functional components: downhole flow rate measurement (using simple differential pressure sensors across a choke), water cut measurement (using gamma ray or other non-intrusive sensors), and statistical estimation (using distributed temperature/pressure sensors). Each segment uses simpler, cheaper sensors rather than requiring a complex integrated MPFM system.
Solution Approach 2:
The invention introduces statistical estimation algorithms as an intermediary that processes data from multiple simple sensors (temperature, pressure, flow rate) to derive accurate multi-phase flow rates. This intermediary computational layer enables accurate measurement without requiring expensive physical flow meters.
2Reliability
If large numbers of subsea sensor elements are deployed to improve measurement reliability, then measurement accuracy is improved, but system weight and cost increase
Solution Approach 1:
The distributed temperature and pressure sensors serve multiple functions: they monitor well conditions, detect flow regimes, and provide input data for the statistical estimation algorithm. This multi-functionality increases measurement reliability without requiring dedicated sensors solely for flow measurement.
Solution Approach 2:
The invention uses optical monitoring systems that create optical copies or representations of the temperature distribution along the wellbore. These optical signals are then processed to extract flow information, enabling reliable measurement with minimal physical sensor mass.
3Device complexity
If downhole flow rate measurement is performed using simple differential pressure sensors, then device complexity is reduced, but measurement precision for multi-phase flow decreases
Solution Approach 1:
The statistical estimation algorithm continuously processes feedback from multiple sensors (downhole flow rate, water cut, distributed temperature, pressure) and adjusts the estimated phase flow rates accordingly. This feedback loop maintains high measurement accuracy despite using simple differential pressure sensors for the primary flow measurement.
Solution Approach 2:
The invention creates a composite measurement system that combines data from multiple different sensor types (differential pressure, temperature, gamma ray, optical) and processes them through statistical algorithms. This composite approach achieves multi-phase flow measurement accuracy comparable to expensive MPFM systems while using simpler individual components.
Data Source
AI summary
A method of determining an estimated flow rate for at least one phase of a multi-phase fluid flowing from a subsea well; a subsea well; and a system for determining an estimated flow rate for at least one phase of a multi-phase fluid flowing from a subsea well are disclosed. The method of determining an estimated flow rate for at least one phase of a multi-phase fluid flowing from a subsea well comprises determining a mass or volumetric flow rate of a fluid in a completion or production tree of a subsea well; determining a Water Liquid Ratio (WLR) of said a fluid via a water sampling device; determining an upstream fluid pressure and an upstream fluid temperature of said a fluid at a location upstream of a production choke valve in the subsea production tree via at least one pressure sensor element and at least one temperature sensor element of the subsea production tree; determining a downstream fluid pressure and a downstream fluid temperature of a fluid at a location downstream of the production choke valve via at least one pressure sensor element and at least one temperature sensor element of the subsea production tree; determining a downhole fluid pressure and a downhole fluid temperature of said a fluid via at least one pressure sensor element and at least one temperature sensor element located downhole in the completion; and providing each of the determined mass or volumetric flow rate, water liquid ratio, upstream fluid pressure, upstream fluid temperature, downstream fluid pressure, downstream fluid temperature, downhole fluid pressure and downhole fluid temperature as respective inputs for a statistical estimator unit and, via the statistical estimator unit, determining an estimated flow rate for each of at least one phase of fluid flowing downstream of the choke valve.