Automated Flow Testing for Hydrocarbon Wells
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Solution Overview
Problem
Conventional flow measurement techniques in hydrocarbon production fields are cumbersome, lack real-time data, and are challenging to maintain, especially in offshore environments, leading to inaccurate and unreliable rate and phase measurements, which hinder effective reservoir management and optimization.
Innovation Solution
An automated system and method for detecting, analyzing, and validating flow tests, providing real-time rate and phase monitoring, and scheduling of flow tests, using a computer system that processes data from downhole and wellhead sensors to update predictive well models and ensure data validity, thereby improving the accuracy and consistency of flow measurements.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If conventional flow meters are used for periodic flow measurements, then flow rate and phase composition data can be obtained, but the measurements lack real-time capability and require frequent recalibration and maintenance
Solution Approach 1:
The patent replaces conventional mechanical flow meters with a system using downhole pressure sensors and wellhead temperature sensors combined with predictive well models. This substitution eliminates the need for physical flow meters that require recalibration, using instead a computational approach based on measured pressure and temperature data to predict flow rates and phase compositions.
Solution Approach 2:
The patent introduces predictive well models as intermediaries between the sensor measurements and the flow rate calculations. These models use pressure and temperature measurements along with well-specific parameters to compute flow rates and phase compositions, serving as a computational mediator that translates basic measurements into meaningful flow data without requiring direct flow metering.
2Reliability
If conventional flow meters are deployed in offshore environments, then flow measurements can be obtained, but maintenance and recalibration become prohibitively difficult and costly
Solution Approach 1:
The patent replaces mechanical flow meters in offshore environments with a sensor-based predictive system. Downhole pressure sensors and wellhead temperature sensors are used with predictive models to calculate flow rates, eliminating the need to service or recalibrate physical flow meters in difficult-to-reach offshore locations.
Solution Approach 2:
The system performs self-calibration through continuous use of predictive models that are updated with new measurements. The predictive well models automatically adjust to changing well conditions using the pressure and temperature data, eliminating the need for external calibration services or manual intervention for maintenance.
3Ease of manufacture
If flow meters are shared among multiple wells to reduce costs, then equipment expenses are reduced, but measurement uncertainty increases
Solution Approach 1:
The patent segments the measurement system so that each well has its own downhole pressure sensor and associated predictive model. This segmentation allows individual well measurements to be made independently using well-specific parameters and models, eliminating the measurement uncertainty that arises from commingled flows in shared metering systems while maintaining cost effectiveness.
4Quantity of substance
If periodic flow tests are conducted to obtain rate and phase information, then data can be collected, but real-time monitoring capability is lost
Solution Approach 1:
The patent implements continuous monitoring by using downhole pressure sensors and wellhead temperature sensors that continuously measure well conditions, combined with predictive well models that continuously calculate flow rates and phase compositions. This provides uninterrupted real-time data rather than periodic snapshots, enabling timely reservoir management decisions.
Data Source
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AI summary
Automated monitoring and management of well tests of hydrocarbon wells in a production field. Routing of the output of a well to a flow meter, separated from the output from other wells in the field is detected by a computer system such as a server. Measurement data including the flow as measured by the flow meter, and also other measurements such as temperatures and pressures contemporaneous with the flow meter measurements, are acquired by the computer system; a stable period is identified, over which the flow test measurement data are considered valid. Upon completion of a specified duration or upon a change in the flow environment, the computer system notifies the user of the completion of the flow test. The flow test results can be used to modify predictive well models, with the modification dependent on validation by the user. The system can also plan and schedule future flow tests.