Historically, parameters like junk slot area (JSA), face volume (FV) and hydraulic horsepower per square inch of bit area (HSI) have been used to empirically predict the balling performance of drill bits. These performance gauges, however, generally produce inconsistent results. This paper presents new design features, guided by numerical predictions and the physical properties of actual PDC bit cuttings that reduce bit balling in PDC bits while drilling shales in water-based drilling muds. Validated by drilling simulator tests and field results, the new design criteria are shown to provide consistent reliable methods to reduce PDC bit balling.

The new design methods employ empirical design rules that govern the allowable proximity of two adjacent blades (pinch points) and the profile of the junk slots. These methods are shown to increase the maximum achievable ROP (that ROP where bit balling just begins) by as much as an order of magnitude.

Highly controlled and repeatable drilling simulator tests show that failure to employ the new design rules consistently results in premature bit balling. The drilling simulator provides accurate results for bit sizes up to 12 1/4 in. although the principles most likely apply to all bit sizes.

Additionally, studies using computational fluid dynamics (CFD) in concert with drilling simulator tests indicate that the maximum achievable balling ROP of a PDC drill bit is increased with increased fluid velocity across the cutting structure. The correlation is shown to be valid over a wide range of bit types and sizes. The new bit designs incorporate strategic nozzle placements and new nozzle designs that improve PDC drill bit performance by increasing the fluid velocity across the cutters.


Traditionally, hydraulics has been viewed as the primary tool to optimize bit performance (i.e., increase ROP) and minimize bit balling. In many cases, bit performace has focused primarily on bit balling, recognizing balling to be the fundamental restriction to higher ROPs. The optimization of the hydraulics and cuttings transport beneath drill bits has been the topic of study for several decades. Speer 1 first recognized that the drilling performance of jet bits could be improved by increasing the hydraulic power at the mud pump. Speer postulated that as pump power was increased, a "perfect cleaning" scenario could be obtained where cuttings generated beneath the bit would be evacuated the instant that they were produced, but further increases in pump power would not produce further increases in ROP. Later, bit horsepower was recognized as having a more direct influence on bit performance. Kendal and Goins 2 were the first to develop a method to optimize bit hydraulics by maximizing the horsepower at the bit. They developed a relation that describes the maximum bit hydraulic horsepower in terms of the pump pressure and the parasitic pressure losses incurred in the drill pipe and the drill pipe annulus. Their relation showed that the hydraulic horsepower at the bit was maximum when the parasitic losses were approximately 36% of the total pump pressure. These relations are currently used to design pump liner and bit nozzle sizes so that the hydraulic horsepower at the bit is maximized over the anticipated interval of the bit run.

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