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ISO/TR 27957:2020 — Carbon Dioxide Capture, Transportation and Geological Storage — Temperature Measurement in Wellbores
Guidelines for distributed temperature sensing (DTS) and point temperature measurement in CO2 injection and monitoring wells
1. The Role of Temperature Measurement in CO2 Storage
Temperature is a fundamental parameter in CO2 geological storage operations. It affects every aspect of the storage system: the density and phase behavior of CO2, the rate of geochemical reactions between CO2 and formation minerals, the mechanical behavior of wellbore materials, and the interpretation of pressure monitoring data. Temperature measurements in injection and monitoring wells provide critical information for verifying storage performance, detecting anomalies, and ensuring operational safety. ISO/TR 27957:2020 addresses the specific requirements and best practices for temperature measurement in CCS wellbores.
Developed by ISO/TC 265, this Technical Report covers both distributed temperature sensing (DTS) using fiber optic cables and conventional point temperature sensors (resistance temperature detectors, thermocouples, and semiconductor sensors). It provides guidance on sensor deployment, calibration, data acquisition, data processing, and interpretation methods specifically tailored to the CO2 storage environment. The standard also addresses thermal modeling approaches that complement temperature measurements to provide a comprehensive understanding of downhole conditions.
Unlike conventional oil and gas wells where temperature is often measured primarily at a few discrete points, CO2 storage wells benefit greatly from distributed temperature sensing (DTS), which provides a continuous temperature profile along the entire wellbore. This capability is particularly valuable for detecting the location of CO2 entry points in injection wells and identifying potential leaks behind casing.
2. Distributed Temperature Sensing (DTS) Technology
2.1 Operating Principles and System Components
DTS systems operate by sending laser pulses through an optical fiber and analyzing the backscattered light. Raman scattering components (Stokes and anti-Stokes bands) are temperature-dependent, allowing temperature to be calculated at each point along the fiber. The standard describes the key performance parameters of DTS systems: spatial resolution (typically 1-2 meters), temperature resolution (typically 0.1-0.5°C), measurement range (up to 10 km for single-ended systems, 30 km for double-ended), and sampling interval. The standard emphasizes that DTS system specifications must be matched to the specific wellbore application — a system designed for pipeline leak detection may not have sufficient resolution for injection profiling.
| DTS Parameter | Typical Range | Application Requirement |
|---|---|---|
| Spatial resolution | 1 – 5 m | < 2 m for injection profiling |
| Temperature resolution | 0.01 – 1.0°C | < 0.1°C for leak detection |
| Measurement range | 2 – 30 km | Well-specific (typically < 5 km) |
| Sampling interval | 0.25 – 2 m | Match to spatial resolution |
| Measurement time | 1 – 30 minutes | Depends on required resolution |
2.2 Fiber Optic Cable Deployment Methods
The standard describes several methods for deploying DTS fiber optic cables in CO2 wells. Permanent installations involve clamping the fiber to the tubing string during completion, providing long-term monitoring capability. Wireline-deployed systems can be run temporarily for periodic surveys. Hybrid systems combine permanent and deployable elements. Key deployment considerations include: protection of the fiber from damage during installation and well operations, ensuring good thermal contact between the fiber and the medium being measured (wellbore fluids or formation), and managing fiber connections through the wellhead (feed-through systems). The standard provides detailed guidance on each deployment method with associated advantages and limitations.
DTS fiber installations in CO2 wells face unique challenges compared to oil and gas wells. The high diffusivity of CO2 and the potential for rapid pressure changes require careful attention to fiber sealing at the wellhead. Additionally, the thermal properties of CO2 differ significantly from hydrocarbon fluids, affecting the interpretation of temperature profiles.
3. Point Temperature Sensors
3.1 Sensor Types and Selection
While DTS provides continuous profiling, discrete point sensors remain important for specific applications requiring high accuracy at particular locations — such as at the sandface (reservoir entry point), across packers, and at the wellhead. The standard reviews three main sensor types: resistance temperature detectors (RTDs, typically platinum Pt100), thermocouples (Type E, K, or T), and semiconductor sensors (thermistors). RTDs offer the best accuracy (±0.1°C) and stability but are larger and more expensive. Thermocouples offer wide temperature range and lower cost with moderate accuracy (±0.5°C). Thermistors provide high sensitivity in limited temperature ranges and are well-suited for specific applications such as geothermal gradient measurement.
3.2 Calibration and Verification
The standard establishes calibration requirements for point temperature sensors used in CO2 wellbores. Sensors should be calibrated over their expected operating range using standards traceable to national metrology institutes. Field verification procedures using fixed-point cells (ice bath, gallium melting point) or comparison with a reference sensor are recommended before deployment and at regular intervals during well operations. The standard emphasizes that calibration drift is a significant concern in the CO2 environment due to potential sensor degradation from exposure to CO2 and acid conditions.
4. Temperature Data Interpretation and Thermal Modeling
4.1 Identifying Flow Profiles
The standard provides guidance on interpreting temperature profiles to identify injection and production flow profiles. During CO2 injection, the temperature profile reflects the combined effects of: the native geothermal gradient, Joule-Thomson cooling as CO2 enters the formation (a characteristic cooling effect unique to CO2 injection), the cool-down effect from injected CO2 that is colder than the formation, and frictional heating in the wellbore. By analyzing the temperature profile, the distribution of injected CO2 among different perforated intervals can be determined — intervals receiving more CO2 show greater cooling.
4.2 Leak Detection and Well Integrity
Temperature anomalies can be powerful indicators of well integrity issues. A localized temperature anomaly behind casing may indicate a channel through which fluids are migrating. An abnormal temperature gradient across a packer or cement plug may indicate a leak path. The standard describes interpretation techniques for distinguishing between normal operational temperature variations and anomaly signatures indicative of potential integrity concerns. The combination of DTS profiling with pressure monitoring significantly enhances the diagnostic capability.
From an engineering perspective, the integration of DTS temperature data with pressure monitoring and geochemical sampling provides a powerful multi-parameter monitoring system for CO2 storage. ISO/TR 27957 provides the foundation for this integrated approach by establishing standardized temperature measurement and interpretation practices that ensure data quality and comparability across different projects.
5. Thermal Modeling for System Design
The standard addresses thermal modeling approaches used to design temperature monitoring systems and interpret measured data. Wellbore thermal models predict temperature profiles under various injection scenarios, helping to optimize sensor placement and establish baseline expectations. Coupled thermal-hydraulic-mechanical (THM) models extend this capability to predict the coupled response of the storage formation to CO2 injection. The standard provides guidance on selecting appropriate boundary conditions (surface temperature, geothermal gradient), fluid properties (temperature- and pressure-dependent CO2 properties), and wellbore heat transfer mechanisms (conduction, convection, and the Joule-Thomson effect).
6. Frequently Asked Questions
Q1: What is the typical accuracy of DTS systems for CO2 wellbore monitoring?
A: Modern DTS systems achieve temperature accuracy of ±0.1 to ±0.5°C and spatial resolution of 1-2 meters under optimized conditions. However, field accuracy depends on installation quality, calibration, and operating conditions.
A: Modern DTS systems achieve temperature accuracy of ±0.1 to ±0.5°C and spatial resolution of 1-2 meters under optimized conditions. However, field accuracy depends on installation quality, calibration, and operating conditions.
Q2: How does the Joule-Thomson effect aid CO2 injection monitoring?
A: When CO2 enters the formation from the wellbore, it undergoes a pressure drop that causes significant cooling (negative Joule-Thomson coefficient for CO2 at typical reservoir conditions). This cooling effect is proportional to the mass flow rate into each formation interval, making it a valuable indicator of injection distribution.
A: When CO2 enters the formation from the wellbore, it undergoes a pressure drop that causes significant cooling (negative Joule-Thomson coefficient for CO2 at typical reservoir conditions). This cooling effect is proportional to the mass flow rate into each formation interval, making it a valuable indicator of injection distribution.
Q3: Can temperature monitoring detect CO2 leakage from the storage formation?
A: In some cases, yes. Leaking CO2 migrating upward along a fault or through a degraded cement sheath will create a thermal anomaly due to the Joule-Thomson cooling effect. However, the magnitude of the anomaly depends on the leak rate and formation properties, and may be difficult to distinguish from background variations in some situations.
A: In some cases, yes. Leaking CO2 migrating upward along a fault or through a degraded cement sheath will create a thermal anomaly due to the Joule-Thomson cooling effect. However, the magnitude of the anomaly depends on the leak rate and formation properties, and may be difficult to distinguish from background variations in some situations.
Q4: What are the limitations of DTS for long-term CO2 storage monitoring?
A: DTS systems are generally reliable for long-term deployment, but limitations include: gradual signal degradation due to hydrogen darkening of the fiber (in high-H2 environments), the need for periodic recalibration, and the potential for mechanical damage to the fiber during well interventions.
A: DTS systems are generally reliable for long-term deployment, but limitations include: gradual signal degradation due to hydrogen darkening of the fiber (in high-H2 environments), the need for periodic recalibration, and the potential for mechanical damage to the fiber during well interventions.
