High pressure and high temperature (HPHT) wells especially those with narrow pore / fracture pressure gradient margins present challenges in drilling. Maintaining optimum and low rheology for such wells becomes a challenge where a slight change in the bottom-hole pressure conditions can lead to non-productive time. However maintaining low viscosity profile for a drilling fluid can pose a dual challenge in terms of maintaining effective hole-cleaning and barite-sag resistance. This paper describes the formulation of 95pcf medium-density organoclay-free invert emulsion drilling fluids (OCIEF). These fluids were formulated with acid-soluble manganese tetroxide as weighting agent and specially designed bridging-agent package. The fluids were hot rolled at 300°F and their filtration and rheological properties were measured. The paper describes the static-aging, contamination, HTHP rheology measurements and filter-cake breaking studies of the fluids at 300°F. Particle plugging experiments were performed on both the fluids in order to determine the invasion characteristics and the non-damaging nature of the fluids. These organoclay-free invert emulsion fluids were then field-trialed in different wells with good results. The OCIEFs showed optimum rheology and filtration properties. The fluids gave lower PV, which ensured that the fluid presents low ECD contribution while drilling/circulating. Sag factor analysis for the fluids after static aging for 24 and 48hours showed excellent stability and minimal sag propensity. HTHP rheology showed that the fluids had consistent PV and YP values across a range of temperatures and pressures. Contamination studies showed that the effect of contaminants on the organoclay-free fluid was minimal and any change in properties can be easily controlled using conventional treatments. The paper thus demonstrates the superior performance of the developed fluid in achieving the desired lab and field performance. Field deployment of the 95pcf organoclay-free invert emulsion fluid helped to maintain the required hole stability in the HTHP well. The well was displaced to 95pcf production screen test (PST) fluid and completed with a 4 ½" sand screen.