Temperature Survey

Key Takeaways

• Cement top identification by temperature survey relies on the exothermic heat of hydration of Portland cement (approximately 250 to 420 joules per gram of cement, depending on cement type, with Type I cement evolving more heat than Type III or low-heat cements) which raises the temperature in the annular cement sheath above the geothermal gradient for 4 to 24 hours after placement; the temperature survey run immediately after the cement has achieved initial set (typically 4 to 8 hours after the end of cement pumping, confirmed by the thickening time from the cement job design) shows a temperature anomaly (warm spot) at the top of the cement column where the heat of hydration has not yet dissipated into the surrounding formation, allowing the cement top to be located within 10 to 30 meters of accuracy depending on the time after cementing, the cement volume, and the thermal diffusivity of the formation; below the cement top, the temperature profile follows the geothermal gradient, and above the cement top, the temperature in the mud-filled annulus is cooler; the temperature survey cement-top method was the first quantitative tool for confirming that the cement column had reached the desired height, predating the acoustic cement bond log (CBL) by decades and still used as a cross-check on CBL interpretation when the CBL result is ambiguous.
• Production logging temperature surveys detect fluid entry into the wellbore by measuring the Joule-Thomson cooling effect that occurs when formation gas expands through the perforation tunnels and near-wellbore flow regime into the lower-pressure wellbore: natural gas flowing through a 500 psi drawdown cools by approximately 2 to 5 degrees Celsius as it expands, creating a detectable cold spot on the temperature log at the depth of the gas-producing perforations, while water entry produces a smaller temperature anomaly (because water is relatively incompressible, the Joule-Thomson effect for liquids is much smaller than for gases) that manifests as a deviation from the thermal gradient established by the fluid column above; in an oil well with multiple zones producing at different rates, the temperature log shows a stepped thermal gradient (each producing zone contributes a proportional fraction of total thermal anomaly) that can be interpreted to allocate the production between zones, complementing the spinner flowmeter measurement and providing an independent diagnostic for confirming zone contribution allocation in the production logging interpretation; the combination of temperature anomaly, spinner velocity change, and fluid density change (from the gradiomanometer) at each producing zone is the standard three-tool approach for complete production logging interpretation in cased-hole wells.
• Distributed temperature sensing (DTS) using permanently installed fiber optic cables provides continuous wellbore temperature profiles at high spatial resolution (0.5 to 1.0 meter) and temporal resolution (measurements every 1 to 10 minutes), enabling the monitoring of temperature changes throughout the wellbore in response to production events, stimulation treatments, and long-term field development changes without requiring any wellbore intervention; DTS cables are installed inside the completion (attached to the outside of the production tubing, inside the annulus between tubing and casing, or inside a dedicated control line) and connected to a surface interrogation unit that sends laser pulses along the fiber and measures the backscattered Rayleigh or Raman photons to reconstruct the temperature profile; in horizontal wells, DTS provides a continuous map of the flow contribution along the wellbore that is not achievable with a single-point production logging run (which captures a snapshot of conditions at the moment of logging), allowing the identification of segments that have ceased contributing (possibly indicating liquid loading or screen plugging in gravel pack completions) and the calibration of reservoir simulation models for history matching; the Troll field (Norway), Pompano (Gulf of Mexico), and Gorgon (Australia) LNG wells are examples of large fields where DTS systems have been operating for over a decade, providing invaluable insights into the evolution of zonal production profiles and wellbore conditions over the field's producing life.
• Temperature surveys in steam injection wells (used in thermal EOR operations including cyclic steam stimulation and steam-assisted gravity drainage, SAGD) monitor the steam chest growth by detecting the elevated temperatures (typically 200 to 350 degrees Celsius) in steam-saturated zones, the condensate bank formation (where steam has condensed to hot water, at a temperature near but below the saturation temperature for the steam injection pressure), and the cold oil zone (where steam heat has not yet propagated, at near-original reservoir temperature); in SAGD operations, the temperature survey differentiates between the steam chamber (the continuously growing high-temperature zone where steam condenses and releases latent heat to the bitumen) and the depleted oil zone (where bitumen has been produced and the steam chamber has collapsed), providing data for optimizing the steam injection rate and the ratio of steam injection to bitumen production to prevent steam breakthrough through the depleted zone to the production well; the temperature difference between the steam chamber and the cold bitumen zone is typically 150 to 200 degrees Celsius, providing an unambiguous temperature contrast that makes temperature surveys particularly diagnostic in thermal recovery operations where other logging methods are degraded by the extreme wellbore conditions.
• Static temperature surveys for geothermal gradient measurement require sufficient time after drilling for the wellbore temperature to equilibrate to the undisturbed formation temperature, which was disturbed by the circulation of relatively cool drilling mud during the drilling process; the mud circulation during drilling depresses the borehole temperature below the true geothermal temperature throughout the wellbore, with the temperature disturbance being largest near the surface (where the mud was coolest before it gained heat from the formation while circulating downward) and smallest at depth (where the mud temperature approached the formation temperature during the extended circulation period); the Horner temperature extrapolation method (analogous to the Horner pressure buildup analysis used in well testing) allows the true static formation temperature to be estimated from temperature surveys run at multiple times after circulation ceases (typically 4, 8, and 24 hours), with the extrapolation to infinite shut-in time giving the static geothermal temperature that is used for cement design, completion fluid design (to prevent thermal expansion fracture of trapped fluids), and heat flow analysis for basin modelling.