Modern day oil & gas well costs are driven by drilling performance as time becomes the dominant capital expense source. The ability to lower drilling costs becomes paramount when tight economic margins and high uncertainties/risk exist. Penetration rate decreases drastically in ultra deep formations, and substantial time is spent drilling the deepest section of these wells. Therefore, significant cost savings may be obtained through an improvement in penetration rate in deep formations. This paper shows that in HTHP (High Temperature High Pressure) hard shale/sand environments that PDC (Polycrystalline Diamond Compact) bits paired with water based mud experience 88% improvement in penetration rate than those paired with oil based mud. With this improvement in drilling rate, well costs can be substantially reduced making future ultra-deep hydrocarbon accumulations economically producible. Also observed was a drastic decrease in penetration rate in PDC bits with oil base mud which led to the use of diamond impreg bits, as the water base with PDC still maintained respectable penetration rates. The conventional penetration rate controls are still applicable in this case, but there exists a fundamental difference between the rock/fluid interactions of each mud type. Bit type, operating conditions, formation characteristics, and bit hydraulics are shown to not be the dominant influencing factor of this performance trend. The water base fluids examined have higher filtrate rates than the oil base fluids. However, a consistent data set of increasing filtrate rate corresponding to increasing penetration rate cannot be derived. Therefore filtration characteristics remain as a possible and partial influencing factor behind this data. Future experimental research is needed to confirm or disprove this theory. At this time the actual cause of this behavior is unknown, however the trend has been established showing water base drilling fluids performance versus oil base in the HTHP/hard rock environment.