Distributed Temperature Sensing for Wellbore Flow Distribution
Find Innovative SolutionsGenerate Solutions
Solution Overview
Problem
Current wellbore treatment techniques face challenges in achieving real-time, continuous monitoring of flow distribution during hydraulic fracturing and matrix acidizing, as traditional methods require shut-in periods for data interpretation, which prolongs treatment time and may not provide immediate feedback for optimal diversion strategies.
Innovation Solution
An automated method for continuous quantitative interpretation of Distributed Temperature Sensing (DTS) data during treatment operations, using optical fibers in the wellbore to analyze successive temperature profiles and simulate flow distribution, accounting for thermal exchange phenomena and exothermic reactions, allowing for real-time adjustments during fluid injection.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If traditional flow measurement methods are used during wellbore treatments, then flow distribution can be measured, but the treatment must be stopped for logging operations which extends treatment time
Solution Approach 1:
The patent implements continuous flow measurement during treatment operations using distributed temperature sensing (DTS) technology. Temperature sensors continuously monitor the wellbore throughout the treatment process, eliminating the need to stop treatment for separate logging operations. This continuous monitoring provides real-time flow distribution data while the treatment is actively occurring, maintaining uninterrupted useful action.
Solution Approach 2:
The patent replaces traditional mechanical flow meters with a thermal-based distributed temperature sensing system. Instead of using mechanical sensors that would require physical deployment and retrieval, the system uses optical fibers with temperature sensors that continuously measure temperature gradients along the wellbore, inferring flow distribution from thermal data. This substitution eliminates mechanical constraints and enables continuous operation.
2Loss of information
If real-time flow distribution monitoring is implemented during treatment, then immediate feedback for diversion strategies is achieved, but the system complexity increases
Solution Approach 1:
The patent uses temperature as an intermediary parameter to indirectly measure flow distribution. Instead of directly measuring flow with complex flow meters, the system measures temperature gradients along the wellbore and uses thermal models to infer flow rates. This intermediary approach simplifies the measurement system while providing continuous flow distribution information through optical fiber temperature sensors.
Solution Approach 2:
The distributed temperature sensing system serves multiple functions: it monitors temperature distribution, infers flow rates, tracks treatment progress, and provides real-time feedback for diversion decisions. This single multi-functional system replaces what would otherwise require multiple separate measurement devices, reducing overall system complexity while enabling comprehensive real-time monitoring.
3Measurement precision
If traditional production logging is used to determine flow distribution, then flow rate can be measured, but the method requires the wellbore fluid to be hydrocarbon or water which limits use in corrosive environments
Solution Approach 1:
The patent replaces mechanical flow meters that are sensitive to fluid composition and corrosiveness with a thermal-based optical sensing system. The distributed temperature sensing uses optical fibers that are chemically inert and resistant to corrosion, allowing measurement in any wellbore environment including those with acids, solvents, or other aggressive fluids. The system measures temperature rather than directly measuring flow, eliminating material compatibility constraints.
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
Enables immediate, data-driven decisions during wellbore treatments by reducing shut-in periods and optimizing fluid distribution, potentially shortening treatment duration and improving treatment effectiveness by providing real-time flow distribution insights.
Implementation Method 1
the optical fiber may measure the temperature distribution along the optical fiber based on optical time-domain reflectometry (OTDR)
Implementation Method 2
The inference of flow distribution is based on the amount of temperature 'warm-back' or 'cool down' during the shut-in period after injecting a fluid whose temperature is typically different from the formation temperature
Implementation Method 3
When the injection fluid is a reactant, the analysis becomes more complicated because the reactant (e.g., acid) may generate heat when in contact with the formation
Data Source
Figure 1a~1b
Figure 2
Figure 3a~3b
AI summary
An embodiment for determining a flow distribution of a wellbore during a wellbore treatment comprises disposing an optical fiber into a wellbore, performing a wellbore treatment in the wellbore with the fiber optic in place by flowing a well treatment fluid from the surface and wellbore and into the formation, taking distributed temperature measurements at a time interval with the fiber optic cable during the wellbore treatment operation, and calculating a flow distribution of the wellbore while performing the wellbore treatment.