Multi-Phase Flow Estimation via Thermal Modeling
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Solution Overview
Problem
Current systems fail to accurately measure multi-phase fluid flow rates near the wellbore in subterranean oil and gas wells, leading to inefficiencies in production and injection operations, incomplete information for remedial planning, and inaccuracies in production logging from various zones within the well.
Innovation Solution
A method and system that estimate multi-phase fluid flow rates by modeling static and transient well characteristics, including temperature and pressure measurements, using a computer-based simulation model that iteratively compares measured conditions with model responses to provide accurate and timely estimates of fluid flow rates.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If surface measurement methods (capacitance-probe technique, turbine flow meter) are used to measure multi-phase fluid flow, then total production can be monitored at the wellhead, but downhole multi-phase flow rates near where fluids first enter the wellbore cannot be determined
Solution Approach 1:
The patent replaces direct mechanical measurement systems (flow meters, capacitance probes) with a thermal modeling approach. Temperature responses are measured and used as inputs to a heat flow model that calculates downhole flow rates, eliminating the need for physical flow measurement devices in the harsh downhole environment.
Solution Approach 2:
The patent introduces temperature as an intermediary parameter. Instead of measuring flow rate directly, the system measures temperature responses which are then used by the heat flow model to infer downhole flow rates. This intermediary approach enables indirect measurement where direct measurement is difficult.
2Loss of information
If downhole temperature and pressure sensors are deployed to measure downhole conditions, then real-time downhole data can be obtained, but the system complexity and cost increase
Solution Approach 1:
The patent extracts the measurement function from complex downhole sensor systems and relocates it to the surface. Only temperature and pressure responses need to be measured, which can be done with simpler surface equipment, while the complex flow rate calculation is performed by the heat flow model at the surface.
Solution Approach 2:
The patent creates a virtual model (heat flow model) that replicates downhole conditions and fluid behavior. This model copies the thermal and flow characteristics of the downhole environment, allowing downhole flow rates to be determined without physically placing complex measurement equipment downhole.
3Productivity
If production estimation is performed using only surface metered data, then total production can be tracked, but inefficiencies in production operations and inaccuracies in zone-specific production logging occur
Solution Approach 1:
The patent adds a thermal dimension to production monitoring. By measuring temperature responses and using heat flow modeling, the system provides additional information about downhole flow conditions that complements surface metered data, enabling more accurate zone-specific production assessment.
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 enhances the monitoring of production streams, improves well management decisions, and increases the accuracy and speed of multi-phase flow profiling, leading to improved well productivity and control.
Implementation Method 1
the step of measuring and interpreting the transient temperature characteristics of the subterranean well includes modeling conductive and convective heat flow within the subterranean well
Data Source
AI summary
Methods and systems for estimating multi-phase fluid rates in a subterranean well (10). Stored and measured static (40) and transient (44) well conditions are used to model well conditions for comparison against additional transient data (42) relating to temperature, pressure, and flow. Multi-phase fluid rates are estimated by iteratively comparing well conditions with the model (30) for the well (10). Multi-phase fluid flow estimates may be obtained for the various liquid and gaseous fluids in the well (10) at multiple well locations (24).