In oil and gas fields with challenging development conditions, where multiphase flow, low reservoir permeability, and low flow rates are present, methods for determining “influx composition” can lose their effectiveness. In such situations, well thermometry becomes more important. This technique allows not only for the diagnosis, but also for the quantification of small inflows into the wellbore within the active formation. This paper discusses classical approaches to flow rate determination using thermometry, as well as ways to improve these techniques for various types of formations. Based on numerical simulations using a thermal model, the authors propose an improved technology for conducting transient thermal studies and a method for quantifying the contribution of different formations to the inflow through the calorimetric effect of mixing. Its main difference from existing methods is a more accurate determination of the temperature of the gas–liquid mixture produced by formations, thanks to the combined analysis of thermograms taken at different times during operation and in a shut-in well.