Bottomhole Temperature Logging: Geothermal Surveys, MWD Thermometers, and Temperature Profiles for WCSB Reservoir Characterization
Bottomhole temperature (BHT) in general petroleum engineering usage refers to any temperature measurement acquired at or near the bottom of a wellbore, encompassing the single maximum-reading thermometer (MRT) value recorded on a wireline logging run, the continuous temperature profile acquired by a dedicated temperature logging tool across the full depth interval of an open or cased wellbore, the real-time temperature transmitted to surface by an MWD thermometer sensor in the BHA during drilling, and the flowing wellbore temperature profile acquired during production logging to identify fluid entry zones and thermal anomalies that indicate flow contributions from specific reservoir intervals. The term is used most loosely in everyday WCSB oilfield practice to describe simply "the temperature at the bottom of the well," without specifying whether it is the static formation temperature, the circulating temperature during drilling, or the flowing temperature during production — a source of ambiguity that has led to equipment selection errors when "BHT from the log" (which reflects the degree of post-circulation equilibration at the time of the logging run, not the true undisturbed BHST) is used without Horner correction as the design input for completion packers, ESP motor windings, or cement retarder selection. In contrast to the single-point BHST value discussed under the corresponding glossary entry, BHT as a logging measurement records a continuous temperature profile at every depth from surface to TD, yielding information about the geothermal gradient in different rock types, the presence of warm or cool fluid-conducting fractures or faults, the depth of permafrost in northern WCSB wells (where the permafrost-bedrock boundary appears as a sharp temperature inflection), and the location of fluid loss or gain zones in a drilling operation (thermal anomalies where the mud temperature deviates from the expected gradient indicate fluid influx from a higher-temperature formation or fluid losses into a cooler section). The MWD temperature sensor — a platinum resistance thermometer or thermistor mounted in the MWD collar and transmitting temperature measurements to surface via mud pulse telemetry — provides real-time BHT during the drilling process, giving the driller an early warning when the formation temperature is approaching the MWD tool's maximum operating temperature rating (typically 150-175°C for standard Montney MWD tools) and alerting the MWD engineer to change to high-temperature equipment before the sensor fails. Production temperature surveys in cased producing wells use a high-sensitivity platinum resistance thermometer run on a slow-logging-pass (5-10 m/min) while the well is producing, mapping the subtle temperature anomalies (0.5-2°C departures from the flowing geothermal gradient) that indicate zones contributing to wellbore production — because gas expansion cools the producing fluid (Joule-Thomson cooling), gas-entry zones appear as temperature dips in the flowing wellbore temperature profile, while water injection breakthrough in a producing well appears as a warm anomaly where cooler injection water (at deeper formation temperature) enters the hotter producing wellbore from a swept waterflood interval.
Key Takeaways
- Continuous temperature logging: tool design and geothermal gradient measurement: A continuous temperature logging tool uses a platinum resistance thermometer (PRT) or thermistor sensor calibrated to ±0.1°C accuracy, housed in a slim pressure-rated mandrel run on the wireline at 100-300 m/hr (slower than standard logging speed to allow thermal equilibration of the sensor to the borehole fluid temperature). The resulting temperature log shows the temperature at every depth, from surface to TD, with features that reflect the rock's thermal conductivity (low-conductivity shale intervals show steeper temperature gradients than high-conductivity carbonate intervals at the same depth), fluid-conducting zones (natural fractures or faults that transport warm connate water from depth appear as positive temperature anomalies, cold surface water in shallow fractures as negative anomalies), and wellbore geometry (casing collars create slight temperature perturbations visible on sensitive temperature logs). In WCSB exploratory wells, a temperature log run on the pre-cement wireline suite provides the basis for BHST estimation at all depths simultaneously, not just at TD, and allows construction of a continuous geothermal model for the entire stratigraphic column penetrated by the well.
- MWD downhole thermometer: real-time temperature monitoring and high-temperature alerts: MWD tools transmit a real-time bottomhole temperature measurement (from a sensor in the MWD collar) to surface via mud pulse telemetry, providing the drilling supervisor with the formation temperature as the BHA descends through successive formations. For most WCSB Montney and Duvernay wells, the MWD temperature stays below 120°C at TD and standard-temperature MWD tools are adequate. However, in deep Devonian wells in northeastern Alberta (Norman Wells Devonian, Zama Devonian) and in high-gradient areas of northeastern BC (Horn River, Liard Basin), MWD temperatures at TD can approach 140-160°C — within 10-30°C of standard MWD tool limits. The real-time temperature alert built into modern MWD systems issues a surface warning when downhole temperature exceeds 80% of the tool's rated maximum, allowing the toolpusher to plan a trip to swap to high-temperature tools before sensor failure causes survey loss in the critical curve or lateral sections of a horizontal well. Tool failure without warning in a highly deviated section can require surveying the wellbore position by other means (gyroscopic survey tools) at a cost of CAD 25,000-60,000 per survey run.
- Production temperature survey: Joule-Thomson cooling for gas entry identification in cased wells: When gas flows from a high-pressure reservoir through a perforation into a lower-pressure wellbore, it expands and cools according to the Joule-Thomson coefficient (approximately 4-7°C/MPa for methane at typical Montney production conditions). A gas-entry zone in a cased producer shows as a temperature depression of 0.5-5°C below the expected flowing wellbore temperature gradient on a production temperature survey — a depression visible only while the well is producing, not in the static temperature profile. Multiple gas-entry zones in a multi-stage Montney completion appear as a series of temperature dips at each productive perforation cluster; zones contributing no gas show no temperature anomaly. The production temperature survey combined with a spinner flowmeter log constitutes a zonal inflow profile that allocates production among stages without the complexity of a full production logging tool suite, at approximately 30-40% lower cost. In Viking and Cardium oil wells, gas expansion cooling at the pump intake depth may be observable in temperature logs as a cold spot at the pump setting depth when the pump intake pressure is below the bubble point, confirming that free gas is entering the pump and motivating the installation of a gas anchor as described in the related bottomhole gas separator entry.
- Temperature logging in SAGD wells: steam chamber boundary and inter-well communication: In SAGD producer-injector well pairs, temperature logging of the producer wellbore with the well producing (flowing temperature survey) maps the temperature along the horizontal section, revealing where the steam chamber has grown toward the producer and where it has not. Steam chamber contact zones appear at 200-230°C on the flowing temperature profile (steam condensation temperature at operating pressure); cooler sections (100-150°C) indicate areas where the chamber has not yet reached the producer, and the coldest sections (50-80°C) indicate areas where only cold bitumen is flowing with no steam contribution. Comparing sequential temperature surveys (run every 3-6 months during SAGD ramp-up) shows the progressive growth of the steam chamber along the well pair lateral from the heel to the toe — information used to adjust steam injection rates and identify areas where auxiliary heating or steam redistribution is required to achieve uniform sweep. The temperature log in this context is a production surveillance tool rather than a formation evaluation tool, directly guiding operational decisions that affect the steam-to-oil ratio (SOR) and recovery efficiency of the SAGD pair.
- Permafrost depth identification from temperature logs in northern WCSB and Mackenzie Basin: In northern WCSB wells north of approximately 58° latitude (including the Mackenzie Delta, Norman Wells area, and Liard Basin in NWT and northern BC), the temperature log identifies the permafrost base as a sharp inflection where the temperature gradient changes from near-zero (within the permafrost, where temperature is near 0°C throughout and the gradient is very small) to the normal geothermal gradient below. The permafrost base depth — typically 150-600 m in northern Alberta and NWT, up to 1,000 m in continuous permafrost zones — is a critical wellbore design datum: the surface casing must be set well below the permafrost base to prevent heat from the well from thawing the permafrost and causing casing movement or wellhead subsidence. AER and the NWT OWB require that the surface casing seat be confirmed below the permafrost base using a temperature log, not estimated from regional tables, because local permafrost thickness varies significantly with topography, soil type, and past climate changes in northern WCSB fields.
Production Temperature Survey in a Multi-Stage Montney Horizontal: Zonal Gas Entry Profiling
A Dawson Creek Montney horizontal producer (3,000 m TVD, 90° inclination, 3,200 m lateral, 20 hydraulic fracture stages) is producing 135,000 m³/day of gas at a wellhead flowing pressure of 8 MPa. A tractor-conveyed production temperature survey is run from heel to toe at 8 m/min while the well is producing. Temperature at the heel: 80°C (matching Montney flowing temperature for this field at 8 MPa wellhead pressure). Temperature profile shows 12 distinct cooling anomalies (dips of 0.5-3.2°C) distributed along the lateral, consistent with Joule-Thomson gas cooling at 12 of the 20 fracture stages. Eight stages (40% of total) show no temperature anomaly — these are non-contributing stages, either not fractured or fractured into tight un-drained rock that has already depleted. The 12 producing stages average 11,250 m³/day/stage; the 8 non-contributing stages contribute zero. Findings used to: (1) inform the refracturing strategy for the well by targeting the 8 non-contributing stages; (2) update the pad-level completion model to understand why 40% of stages underperformed; (3) identify the 4 stages with largest cooling anomalies (highest gas entry rates) as candidates for sand production monitoring after the well ages into higher depletion.
Fast Facts
The first continuous temperature logging of an oil well was performed by Evelyn De Golyer and Schlumberger in Louisiana in 1931, using a resistance thermometer lowered on the same cable as the early resistivity logging tools. The temperature log was initially valued only as a quality control check for cement top location (cement hydration generates measurable heat that appears as a warm anomaly above the cement top on a post-job temperature survey), a use that remains relevant in WCSB cementing practice today — but the realization that temperature profiles contain information about formation fluid flow, geothermal gradient, and production zonal allocation has transformed the temperature log into one of the most versatile and underutilized tools in the WCSB formation evaluation and production optimization toolbox.
Related Terms
The undisturbed static formation temperature at total depth — the single most important temperature parameter for equipment design, cement selection, and reservoir simulation — is described under bottomhole static temperature, which covers the Horner correction method for estimating BHST from the logged maximum recorded temperatures and the engineering applications of BHST in downhole equipment specification for WCSB well programs. The Joule-Thomson cooling effect that makes gas-entry zones visible on production temperature surveys is described in the context of gas reservoir fluid behavior under gas condensate, where expansion cooling and retrograde condensation in the producing wellbore are covered alongside the near-wellbore temperature management strategies used to prevent condensate dropout in tight Montney gas condensate wells. The cement top identification and zonal isolation confirmation using post-job temperature logs in WCSB casing programs is described under bond log.