Wellbore Flowrate Estimation Using Marker Fluid Tracking
Find Innovative SolutionsGenerate Solutions
Solution Overview
Problem
Existing well evaluation methods, such as traditional well tests, are time-intensive, require field personnel presence, and provide outdated flowrate data due to the complexity of multi-phase fluid mixtures and the difficulty in obtaining real-time in-line flowrate measurements, leading to infrequent testing and outdated performance data.
Innovation Solution
The method involves monitoring pressure in tubing with a detectable marker fluid introduced under similar conditions to estimate real-time flow velocity and flowrate, allowing for continuous data collection without interrupting production and enabling adjustments to lift fluid addition to maintain desired production levels, using sensors to track the marker fluid's progression and calculate slip coefficients for accurate flowrate estimation.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If traditional well tests are performed to measure flowrate, then measurement precision is improved, but loss of time increases and productivity decreases
Solution Approach 1:
A marker fluid is introduced as an intermediary substance to track flow velocity. The marker fluid moves with the production fluid through the tubing, and its position is detected at two locations to calculate flow velocity, which then allows estimation of production fluid flowrate without directly measuring the multi-phase mixture
Solution Approach 2:
The complex mechanical well testing system that requires personnel presence and direct measurement of multi-phase flow is replaced with a simpler system using marker fluid tracking and pressure sensing. The flowrate is estimated through mathematical relationships rather than direct mechanical measurement of the production fluid
2Measurement precision
If traditional well tests are performed to obtain flowrate data, then measurement precision is improved, but device complexity increases
Solution Approach 1:
The marker fluid serves as a simplified intermediary that avoids the complexity of directly measuring multi-phase flow. Instead of complex sensors to measure oil, water, and gas flow separately, the system uses a single marker fluid whose movement can be tracked with simple pressure sensors
Solution Approach 2:
The system changes the measurement parameter from direct multi-phase flow measurement to marker fluid velocity measurement. By tracking the position of the marker fluid front at two different locations and calculating its velocity, the system derives production flowrate through established relationships, simplifying the measurement approach
3Loss of time
If well tests are performed infrequently due to time constraints, then loss of time is reduced, but reliability of performance data deteriorates
Solution Approach 1:
The system enables continuous or frequent flowrate monitoring by using a quick marker fluid injection and detection method. Multiple flowrate measurements can be obtained over time as the marker fluid moves through the tubing, providing ongoing performance data rather than single infrequent snapshots
Solution Approach 2:
The marker fluid is injected in advance into the tubing before the production fluid flows past the detection points. This preliminary introduction of the marker allows its position to be tracked as it moves with the production fluid, enabling flowrate calculation without interrupting production
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 approach allows for real-time well performance monitoring, reducing the need for personnel and enabling frequent data updates, enabling more precise control of production fluid flow and improving the accuracy and timeliness of well performance assessment.
Implementation Method 1
pressure in the tubing is monitored over time and at spaced apart locations, and a detectable marker fluid is introduced into the tubing
Implementation Method 2
A lift fluid is added to the tubing
Implementation Method 3
pressure in the tubing is monitored over time and at spaced apart locations
Implementation Method 4
An amount of marker fluid is introduced into the tubing having a density different from a density of the mixture
Data Source
AI summary
A method of estimating a real time production flowrate from a well by estimating a real time flowrate of a marker fluid in the well, and comparing the estimated flowrate with a baseline marker fluid flowrate; where the baseline marker fluid flowrate correlates to baseline production fluid flowrate. The baseline marker fluid flowrate is obtained by introducing an amount of a marker fluid in the well, monitoring the time over which the marker fluid travels a set distance, and estimating a flowrate of the marker fluid based on the monitored time and amount of marker fluid. The real time production flowrate is obtained by extrapolating the baseline production fluid flowrate by an amount derived from a comparison of the baseline and real time marker fluid flow rates.