Distributed Temperature Log (DTS)
A distributed temperature log (DTS) is a continuous, full-wellbore temperature profile acquired by deploying a single-mode or multimode optical fiber cable in the wellbore and interrogating it with pulsed laser light, where spontaneous Raman backscattering from thermally excited silica molecules at every point along the fiber encodes local temperature with centimeter-scale spatial resolution and temporal sampling intervals of seconds to minutes, yielding a dynamic 2-D temperature map of depth versus time that conventional point-sensor thermometers cannot produce.
Key Takeaways
- DTS uses the ratio of anti-Stokes to Stokes Raman backscatter intensities, which are temperature-dependent, to compute absolute temperature at every point along the fiber without requiring any downhole electronics or power sources.
- Spatial resolution is typically 0.5 to 2.0 meters along the fiber, with measurement uncertainty of plus or minus 0.1 to 0.5 degrees Celsius depending on fiber length, instrument quality, and averaging time.
- Permanent fiber installations behind casing or in the annulus allow continuous real-time temperature monitoring throughout the life of a well, enabling production profiling, injection surveillance, and integrity monitoring from surface.
- In SAGD operations, DTS fibers deployed in both the injector and producer well pair track steam chamber growth in real time, allowing operators to optimize steam injection rates and identify zones of poor conformance.
- DTS complements distributed acoustic sensing (DAS) when both fiber types are co-deployed, providing simultaneous thermal and acoustic wellbore data for comprehensive flow profiling and hydraulic fracture diagnostics.
Fast Facts
A DTS interrogator unit typically emits laser pulses at 1064 nm or 1550 nm and measures the time-of-flight of returning Raman photons to determine their origin depth (optical time domain reflectometry). A single fiber can monitor wellbores exceeding 10 km in length. Stainless steel or carbon-coated fibers rated to 300-plus degrees Celsius are used in steam injection and HPHT wells, while standard telecom-grade fiber suffices in most conventional production wells below 150 degrees Celsius.
Tip: DTS temperature anomalies alone cannot distinguish between gas entry, water entry, and crossflow without additional context. Always interpret DTS data alongside pressure data, flow rate, and fluid composition logs to correctly attribute thermal signatures to specific production or injection events.
What Is a Distributed Temperature Log
A distributed temperature log is the output from a DTS system: a continuous depth-versus-temperature profile, often acquired repeatedly over time to create a time-lapse dataset. Unlike conventional wireline temperature logs, which record temperature at a single point as the tool traverses the wellbore (a one-time snapshot), DTS captures temperature simultaneously along every meter of fiber at user-defined time intervals ranging from seconds to hours. This temporal dimension is the defining advantage of DTS over all point-sensor alternatives.
The fiber itself is the sensor. No electronic components exist downhole; the physics of Raman scattering in silica glass performs the measurement. This makes DTS inherently reliable in harsh environments, compatible with permanent installation, and immune to the high-temperature degradation that limits electronic downhole sensors in steam injection or geothermal wells.
How a Distributed Temperature Log Works
The DTS interrogator at surface emits a short laser pulse that travels down the fiber. At every point along the fiber, a tiny fraction of light is scattered back toward the source. Most scattered light returns at the same wavelength as the incident pulse (Rayleigh scattering), but a small fraction undergoes Raman scattering and returns at two shifted wavelengths: the Stokes band (longer wavelength, lower energy) and the anti-Stokes band (shorter wavelength, higher energy). The intensity of the anti-Stokes band is strongly temperature-dependent, while the Stokes band is nearly temperature-independent. The ratio of anti-Stokes to Stokes intensity at each depth point, combined with a factory calibration, yields absolute temperature with no downhole electronics.
Time-of-flight of the returning photons determines the depth of origin via the known speed of light in glass (approximately 2 x 10^8 m/s in silica fiber). The instrument integrates returning photons over many pulse repetitions to improve signal-to-noise ratio; the time required to achieve acceptable temperature resolution depends on fiber length, fiber attenuation, and required spatial resolution. A 5 km fiber typically requires 30 to 120 seconds of averaging to achieve 1-degree Celsius accuracy at 1-meter resolution.
In production profiling applications, the DTS fiber is run inside tubing, in the annulus, or strapped to the outside of production casing before cementing. Flowing fluid entering the wellbore from perforated zones causes local temperature anomalies: gas entry creates cooling from Joule-Thomson expansion, water entry appears as a thermal contrast against the geothermal gradient, and crossflow between zones creates distinctive temperature plateaus or inversions. Interpreting these signatures requires forward modeling of wellbore heat transfer using reservoir temperature, flow rate, and fluid thermal properties.
Distributed Temperature Logging Across International Jurisdictions
In Canada, DTS has found its most widespread application in SAGD (steam-assisted gravity drainage) operations in the Athabasca and Cold Lake oil sands of Alberta. Canadian Natural Resources Limited, Cenovus Energy, and Suncor Energy routinely install permanent DTS fibers in both the horizontal injector and producer well pairs of SAGD well pairs. The Alberta Energy Regulator (AER) requires operators to demonstrate conformance between the injected steam and the producing zones; DTS temperature profiles provide the spatial evidence needed to show that steam is contacting the intended bitumen intervals and not channeling to unintended zones or outside the lease boundary.
In the United States, DTS is used by the Bureau of Safety and Environmental Enforcement (BSEE) as part of offshore well integrity monitoring programs. Operators in the Gulf of Mexico install DTS fibers in deepwater completion strings to monitor annular temperature during cementing (to detect gas migration through the cement) and during production to track water or gas breakthrough. Onshore, operators in the Permian Basin and Eagle Ford use DTS in conjunction with distributed acoustic sensing (DAS) during hydraulic fracturing operations to identify which perforation clusters are accepting fluid and which are screenout-limited.
In Norway, Equinor and other NCS operators deploy DTS in subsea completion systems and in long-offset horizontal wells in Jurassic and Cretaceous reservoirs. The Norwegian Offshore Directorate (Sodir) includes DTS data in well completion reports for fields where permanent fiber installations are used. Norwegian operators have used DTS to detect annular gas flow in cemented sections, a critical well integrity application given the strict regulatory requirements for zero sustained casing pressure on the NCS.
In the Middle East, Saudi Aramco has integrated DTS into its maximum reservoir contact (MRC) well programs, deploying fibers in multilateral completions to monitor inflow distribution across multiple laterals simultaneously. High bottomhole temperatures (often 120 to 180 degrees Celsius) in deep carbonate reservoirs require fiber cables rated to these conditions; Aramco and other regional operators have qualified high-temperature fiber systems that maintain calibration accuracy for years of continuous service in these environments.
Synonyms and Related Terminology
DTS is also referred to as fiber optic temperature sensing, Raman DTS, or distributed temperature sensing. It belongs to the broader family of fiber optic sensing technologies, which also includes distributed acoustic sensing (DAS) and distributed strain sensing (DSS). The permanent installation variant is sometimes called a permanent downhole monitoring system. In thermal recovery contexts, DTS is closely associated with SAGD steam chamber monitoring. The interpretation workflow overlaps with conventional temperature log analysis but adds the time dimension that conventional logs lack.
FAQ
How does DTS differ from a conventional wellbore temperature survey?
A conventional temperature survey records temperature at one depth at a time as a tool moves through the wellbore; the measurement is a single snapshot in time and is influenced by tool movement speed and wellbore flow conditions during the logging run. DTS records temperature at every depth simultaneously and continuously, allowing operators to distinguish steady-state thermal profiles from transient events such as a gas kick, an injection pulse, or a hydraulic fracture stage. The continuous temporal record is impossible to replicate with point sensors.
What limits DTS accuracy in very long wellbores?
Fiber attenuation causes the returning Raman signal to weaken with distance from the interrogator. In a 10 km fiber, the anti-Stokes signal at the far end may be 100 times weaker than at the near end. Longer averaging times compensate for weaker signals but reduce temporal resolution. Dual-ended DTS configurations, where the interrogator accesses both ends of the fiber via a surface loopback, correct for fiber attenuation along the entire length and maintain accuracy in long or high-loss installations.
Why Distributed Temperature Logging Matters
DTS has transformed well surveillance from a periodic, labor-intensive wireline operation into a continuous, automated monitoring capability. In SAGD operations, real-time DTS data can increase steam utilization efficiency by 10 to 20 percent by allowing operators to redirect steam away from swept zones and toward uncontacted bitumen. In offshore integrity monitoring, early detection of sustained casing pressure via DTS temperature anomalies can prevent the slow gas migration that leads to surface casing vent flows or subsea wellhead pressure buildup. In hydraulic fracturing, DTS-based cluster efficiency measurements allow completion engineers to redesign perforation spacing and diversion strategies to improve the percentage of clusters that contribute to production. These economic and safety contributions make DTS one of the highest-value diagnostic tools in modern well management.