Active-Source Thermal Profiling for Zonal Flow Allocation
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Solution Overview
Problem
In hydrocarbon wells, especially highly deviated or horizontal wells, traditional methods for determining flow profiles are hindered by uniform fluid entry temperatures and the interference of temperature spikes from mechanical heating systems, which complicates zonal allocation and requires complex and costly installation processes, and are not designed to handle extreme temperatures and pressures.
Innovation Solution
A method involving a temperature change induced within the wellbore using a heating or cooling source, measured by distributed temperature sensing systems, to generate a simulated heat flow profile and determine fluid flow direction and cumulative flow rates without relying on mechanical spinners or large diameter tubing, suitable for extreme conditions.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If mechanical heating systems are used to create temperature differences for flow profiling, then temperature measurement capability is improved, but temperature spikes from the heating systems interfere with measurements and complicate zonal allocation
Solution Approach 1:
The patent replaces mechanical heating systems with an electrical heating element that can be precisely controlled and positioned. This substitution allows for more accurate temperature control and eliminates the uncontrolled temperature spikes associated with mechanical heating, thereby resolving the measurement interference issue while maintaining flow profiling capability
Solution Approach 2:
The patent introduces a thermal model as an intermediary between the heating element and the measurement system. This model simulates the expected temperature distribution and allows for differentiation between heating-induced temperature changes and flow-induced temperature variations, enabling accurate flow profiling despite the presence of heating effects
2Measurement precision
If traditional mechanical spinner surveys are used for zonal allocation, then flow rate measurement is achieved, but the method is unduly influenced by gas presence and wellbore geometry in multi-phase flows
Solution Approach 1:
The patent replaces mechanical spinner surveys with a thermal-based measurement system using distributed temperature sensing and active heating. This substitution eliminates the mechanical components that are sensitive to gas presence and wellbore geometry, providing a measurement method that is insensitive to these factors while maintaining accuracy in multi-phase flow conditions
Solution Approach 2:
The patent changes the measurement parameter from mechanical rotation speed (spinner) to temperature distribution. This parameter change allows for flow profiling in multi-phase flows where mechanical methods fail, as temperature measurements are not influenced by gas presence or wellbore geometry in the same way mechanical measurements are
3Measurement precision
If standalone temperature logging via permanently installed DTS systems is used, then zonal allocation in deviated and vertical wells is improved, but the method relies on small temperature differences that are difficult to measure in highly deviated or horizontal wells
Solution Approach 1:
The patent applies preliminary heating to the wellbore fluid before the natural flow process. By actively heating the fluid at a controlled location upstream, the system creates a larger initial temperature difference that is more easily measurable downstream, thereby improving the signal-to-noise ratio for zonal allocation measurements in highly deviated or horizontal wells
Solution Approach 2:
The patent actively modifies the temperature parameter through controlled heating rather than relying on passive temperature differences. This parameter change creates a more pronounced thermal signature that enhances measurement capability in wells where natural temperature gradients are minimal
4Length of moving object
If large diameter coiled tubing is used to convey measuring devices in long horizontal wells, then device delivery is achieved, but the device takes up larger cross-section and increasingly alters the flow inside the wellbore
Solution Approach 1:
The patent replaces the need for physical conveyance of measuring devices through coiled tubing with a system where the optical fiber is permanently installed and the heating element is deployed through standard wellbore access. This substitution eliminates the flow-altering effect of large diameter tubing while maintaining the ability to reach long horizontal wells
Solution Approach 2:
The patent segments the measurement system into separate components: a permanently installed optical fiber for temperature sensing and a separately deployable heating element. This segmentation allows each component to be optimized independently, with the heating element being delivered through smaller diameter tubing that has minimal impact on wellbore flow
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 accurate allocation of fluids across multiple zones in hydrocarbon wells by creating measurable temperature differences, effectively modeling heat transfer and calculating flow rates, even in challenging environments, reducing installation complexity and costs.
Implementation Method 1
A temperature change is effected in the fluid at a first location in the wellbore
Implementation Method 2
A temperature change is effected in the fluid at a first location in the wellbore
Implementation Method 3
Due to interactions with molecular vibrations within the glass of the fiber, a portion of the light is scattered back towards the surface (this phenomenon is referred to as Raman scattering and/or Rayleigh scattering)
Implementation Method 4
generating a simulated heat flow profile from a wellbore model
Data Source
AI summary
A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid at a first location in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A simulated heat flow profile is generated from a wellbore model. The simulated heat flow profile is compared to the measured temperature of the fluid at the one or more sensing locations. An inversion model is used to determine, for a plurality of points of interest, a fluid flow direction and/or a cumulative flow rate contribution.