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.

In efforts to render the safest, fastest, and most cost efficient drilling program for a high temperature and high pressure (HT/HP) well the maximization of drilling operational efficiencies is key. Designing an adequate, HT/HP well specific, drilling fluid is of most importance and a technological challenge that can greatly affect the outcome of the overall operational efficiency. It is necessary to have a sound fundamental understanding of the behavior that water-based muds (WBM) exhibit when exposed to HT/HP conditions. Therefore, in order to adequately design and treat a WBM for a HT/HP well specific drilling program, it is essential that the mud be evaluated at HT/HP conditions. Currently, industry standard techniques used to evaluate WBM characteristics involve aging the fluid sample to a predetermined temperature, based on the anticipated bottom hole temperature (BHT), either statically or dynamically, for a predetermined length, then cooling and mixing the fluid and measuring its rheological properties at a significantly lower temperature. This, along with the fact that the fluid is not subjected to the anticipated bottom hole pressure (BHP) during or after the aging process, brings to question if the properties recorded are those that are truly experienced down-hole. Furthermore, these testing methods do not allow the user to effectively monitor the changes during the aging process. The research in this thesis is focused on evaluating a high performance WBM and the current test procedures used to evaluate their validity. Experimental static and dynamic aging tests were developed for comparative analysis as well to offer a more accurate and precise method to evaluate the effects experienced by WBM when subjected to HT/HP conditions. The experimental tests developed enable the user to monitor and evaluate, in real-time, the rheological changes that occur during the aging of a WBM while being subjected to true BHT and BHP. Detailed standard and experimental aging tests were conducted and suggest that the standard industry tests offer false rheological results with respect to true BHT and BHP. Furthermore, the experimental aging tests show that high pressure has a significant effect on the rheological properties of the WBM at elevated temperatures.