Temperature is a parameter of great importance when simulating and modeling cementing or temperature-activated fluids (McSpadden and Glover 2008) because it affects the amount of retarders or accelerators needed to avoid undesired phenomena, such as premature cement setting or incomplete consolidation of the treatments. In 1964, API introduced the first set of tables (API 2005) that listed the circulating temperatures and hydrostatic pressures for certain wellbore circumstances and bottomhole conditions and the fluids that could be used in different well treatments, such as cementing, lost-circulation control, and water or gas control, etc. The API procedures have been widely adopted and recognized in the oil industry, and most operating companies feel comfortable using them. However, increased demand for oil and gas has forced operators to perform drilling, completion, and maintenance operations in deeper and more complicated zones. These zones are often classified as high-pressure/high-temperature (HPHT) fields. Currently, combining computational tools, such as computer simulation software and measurement sensors, allows operators to accurately measure temperature and pressure values and adjust them with well-known heat-transfer models; as a result, possible temperature changes during complex operations can be more accurately modeled. This paper presents multiple case histories showing the significance of using bottomhole pressure/temperature (P/T) measurement tools and the modified modeling of the heat-transfer effects as a function of operational parameters (flow rate, density, wellbore geometry). With more accurate temperature data, laboratory testing can be performed to better predict the behavior of the treatments mentioned when exposed to the more complex bottomhole conditions encountered.