A comparison has been made of the results obtained with a new soft formation PDC bit (the Security STRAT-X Bit) and those obtained in a wide range of formations with the various types of PDC bits currently available. The results indicate that, at present, PDC bits are special products for special situations. The clearly products for special situations. The clearly superior results have been obtained in homogeneous soft formations when the bit hydraulics and application practices have been appropriate for the particular bit design involved. Very high penetration rates particular bit design involved. Very high penetration rates and significant reductions in cost/foot have been achieved when bit design, hydraulics, mud and application practices have been matched well with the bit characteristics. However, even the newest and most productive PDC bits cannot compete when the formation productive PDC bits cannot compete when the formation is unsuitable for the particular bit design in combination with the drilling fluid and the hydraulics available. A review of several specific examples in South Texas, the North Sea, and the Rocky Mountains illustrate what can be done with currently available PDC bits, and how to identify those circumstances under which PDC bits should not be run. The results also indicate how to identify when a formation change requires that a PDC bit be pulled or when one can drill through hard streaks and retain the high productivity of the PDC bit for the softer portions of the formation. Maintaining a full gage portions of the formation. Maintaining a full gage hole under these conditions is shown to depend critically on bit design and control of weight and rpm.
Recent reports and publications have indicated that polycrystalline diamond cutter (PDC) bits can produce higher penetration rates and lower cost per foot in a variety of formations throughout the world. In those circumstances where formation properties, bit design and application practices are properties, bit design and application practices are appropriate, PDC bits have produced spectacular results. On the other hand, the variations normally seen in the depth, thickness, and properties of various formations have often lead to disappointing results and non-economic runs with PDC bits. Because of the variety of PDC bit designs currently available, and the critical importance of application engineering and drilling practices, it is often difficult to determine which of these factors are primarily responsible for a given unsuccessful run. primarily responsible for a given unsuccessful run. It is the purpose of this paper to shed some light on how one can decide whether or not to run PDC bits, and what application practices should be PDC bits, and what application practices should be avoided to improve the probability for successful runs with PDC bits.
How not to run PDC bits (application practices which cause premature damage to PDC bits or prevent achievement of optimum results.)
Inadequate hydraulics to cool PDC cuttersand clean the bit.
Inadequate hydraulics to carry cuttings to the surface at high penetration rates typical of PDC bit operation.
Inadequate solids separation equipment to keep up with high penetration rates.
Running without a shock absorber in formations which tend to cause drill string bounce.
Running with a packed hole assembly after the hole has deviated from vertical in straight hole drilling.
Running a stabilizer too close to the bit in a pendulum assembly when trying to bring a deviated hole back to vertical.
A PDC bit will not cut the formation if the cutting edge of the tool is not kept clean and cool. The hydraulic horsepower per square inch of hole must be high in a soft formation to assure proper cleaning and cooling of the cutting tool. proper cleaning and cooling of the cutting tool. P. 249
