PTA is a Reservoir Engineering tool when we derive insitu permeability to oil, gas, or water. Remember, PTA analytical equations solve not for permeability (k), but transmissivity (kh/µ); net pay (h) and viscosity (µ) are assumed to be constant to derive perm’ (k). Which of course is not necessarily true. Depositional variations in net pay thickness or fluid viscosity interfaces (gas/oil or gas/water) can affect the pressure derivative and confuse quantification of permeability. Relative permeability is also critical because fluid saturations can change over time through several mechanisms. Induced fracture stimulation load fluids alter near wellbore fluid saturations, temporarily decreasing relative permeability to oil, until load fluids are fully recovered. Retrograde condensates drop liquids out in the reservoir, starting with the bottom hole drawdown at the perforations, so increasing liquid saturation appears as increasing skin. Volatile oils are the opposite, gas breaks out in the formation, due to drawdown pressure differentials, increasing gas saturation, decreasing relative permeability to oil. Secondary recovery waterfloods, and tertiary miscible floods also change reservoir saturations and relative permeability to insitu fluids.