Maximum Recorded Temperature

Key Takeaways

• The Horner plot method is the standard industry technique for correcting maximum recorded temperature to true static formation temperature when multiple BHT measurements are available at different times after circulation: analogous to the Horner pressure buildup analysis used in well testing, the Horner temperature plot graphs the maximum recorded BHT measurements on the Y-axis versus the Horner time ratio log[(t_c + delta_t) / delta_t] on the X-axis, where t_c is the total circulation time at bottom before the logging run and delta_t is the time elapsed since circulation stopped; if the temperature recovery follows a logarithmic function of the Horner ratio (as theory and field experience indicate for most formations), the data points plot on a straight line, and extrapolation of the line to the Horner ratio of 1 (which represents infinite shut-in time, i.e., the point where no more temperature recovery occurs) gives the true static formation temperature; a single BHT measurement does not allow Horner extrapolation, and empirical correction charts (published by Lachenbruch and Sass, 1977; Deming, 1989; and others) based on statistical analysis of well data in various geological provinces provide estimates of the undershoot percentage (typically 5 to 30 percent of the temperature difference between surface and TSFT) as a function of measured BHT and well depth; the American Association of Petroleum Geologists (AAPG) BHTEMP dataset provides regional BHT correction factors for US sedimentary basins derived from regression of Horner-extrapolated temperatures against single-measurement BHTs.
• The timing of the logging run relative to the end of circulation critically affects how close the maximum recorded temperature is to the static formation temperature: wells that log immediately after reaching total depth (TD) while the borehole is still significantly cooled by circulation may have maximum recorded temperatures 20 to 50 degrees Celsius below TSFT for deep, hot formations (where the geothermal temperature may be 150 to 200 degrees Celsius); wells that allow 6 to 12 hours of temperature recovery before logging may be within 5 to 10 degrees of TSFT; industry practice generally requires at least 8 hours of temperature recovery before the logging run for accurate BHT measurements in wells deeper than 3,000 m in geothermally active areas, but the economic pressure to log and case the well quickly often overrides this requirement, leading to systematically low BHT measurements in many well datasets; in offshore wells where rig time costs $500,000 to $1,000,000 per day, an 8-hour temperature recovery delay adds $170,000 to $330,000 to the well cost, which is rarely acceptable unless the temperature data is specifically required for a formation evaluation objective (such as measuring the geothermal gradient in an exploration well for regional heat flow mapping).
• Maximum-reading thermometer design for wireline logging tools uses liquid-in-glass (mercury or alcohol) thermometers with a constriction below the bulb (analogous to a clinical fever thermometer) that traps the mercury column at the maximum reading during the descent of the tool string, or bimetallic strip mechanisms that deform under heat and lock at the maximum deflection; electronic maximum-reading circuits (using analog peak-hold circuits or microprocessor-based data logging with maximum-value retention) provide more precise readings and allow the temperature-time profile to be recorded rather than just the single maximum value, enabling the geothermal gradient to be computed from the temperature versus depth profile (the slope of the profile below the neutral point, where the tool temperature begins to exceed the circulating fluid temperature); electronic thermometers in modern logging tools (resistivity, acoustic, NMR, and formation tester tools) routinely record temperature at each depth level during the logging pass, providing a continuous temperature log that is more useful than a single MRT value for formation evaluation purposes and for detecting permafrost, hydrate zones, and thermal anomalies associated with hydrocarbon-bearing intervals (which may have anomalously high or low thermal conductivity relative to surrounding shales).
• Log interpretation corrections that depend on formation temperature include resistivity log corrections (resistivity of the formation water and hence the formation itself decreases with increasing temperature at a rate of approximately 2 to 3 percent per degree Celsius, so using an incorrect temperature in the Archie water saturation calculation introduces systematic errors in Sw), density log corrections (the bulk density of the formation fluid changes with temperature and pressure, affecting the density log reading for gas reservoirs at high temperature), neutron log corrections (the neutron log response is temperature-sensitive in some tool designs), and NMR relaxation time corrections (T1 and T2 relaxation times are temperature-dependent, affecting the NMR permeability and porosity interpretation); the formation temperature at each logging depth is computed from the measured maximum BHT and the assumed geothermal gradient (derived either from a temperature log or from regional geothermal gradient data), with the gradient extrapolated from the surface temperature to TD; in basins with unusual geothermal gradients (high in geothermally active areas like the Gulf of Mexico, Salton Sea, and volcanic provinces; low in thick cratonic sedimentary sections and in areas of recent glacial cooling), using a regional gradient rather than a well-specific gradient measurement introduces interpretation errors that propagate through the entire log interpretation workflow.
• Cement design for well completion uses the maximum recorded temperature (corrected to TSFT) to select appropriate retarder additions to prevent flash set (premature hardening before cement reaches its designed location) or to select accelerators for shallow, cold wells: API Class G Portland cement has a normal thickening time of 90 to 180 minutes at 60 to 80 degrees Celsius (API test conditions), but thickening time decreases dramatically with temperature (50 to 90 minutes at 100 degrees Celsius, 20 to 40 minutes at 150 degrees Celsius without retarder), making retarder selection critical for cement jobs in hot wells; the bottomhole circulating temperature (BHCT, the wellbore temperature during cement pumping, which is lower than the static BHT because of cooling by circulation) is distinct from the static bottomhole temperature (BHST) used for cement strength development design; API RP 10 specifies standard procedures for estimating BHCT and BHST from the maximum recorded temperature and circulation data, with BHCT used for thickening time tests and BHST used for compressive strength development tests; incorrect temperature inputs to cement design cause either flash set (if the cement is too sensitive for the BHCT) or strength retrogression (if the cement formulation is not adapted for the BHST), both of which can result in loss of zonal isolation and the need for expensive remedial cement squeezes.