An extensive data collection, training, and field trial program was implemented to develop practices to mitigate a common form of bit damage in hard laminated formations. Analysis improved understanding of the physical phenomena causing the damage and a variety of operational practices and technical redesigns have resulted in reduced levels of bit dysfunction, increased bit life, as well as increased drill rate.

In hard laminated formations, bit life is often limited by severe damage occurring in only the two outside cutter rows on the bit shoulder (Fig. 2). In 2014, the operator began a performance improvement program in the Greater Green River Basin, which included investigating the physical process through which this damage was occurring. High frequency downhole vibrations data was recorded on multiple wells at points throughout the BHA as well as at the bit. The data revealed that synchronous torsional oscillations (STO) were occurring, and these were enabling high lateral bit whirl. While the root cause is a form of stickslip, the damage observed has the appearance of whirl. Analysis showed that as the bit drilled the laminated interfaces, higher modes of STO may occur along with the basic primary torsional oscillation mode. STOs occur when the drillstring is rotated at specific speeds that cause higher frequency torsional resonance to develop in addition to the primary large torque and speed cycles that rig crews observe with stickslip. The high frequency oscillation within the drillstring had small amplitude, but it created sufficient loss of depth of cut that allowed the bit to move freely in the lateral direction, enabling high lateral vibrations. The effect is particularly pronounced in hard laminated formations where the depth of cut has already declined at each transition due to the increase in rock hardness.

It has generally been observed by the industry that high levels of whirl are rarely seen simultaneously with high stickslip. The observations in the described case are significant in that they may explain those instances where they are seen together. Also, the operations personnel are generally not aware that primary and higher order torsional oscillations may be excited by specific rotary speeds and that new field practices are needed to identify and avoid these in real time. Field trials were conducted that included RPM step tests to determine non-resonant rotational speeds, WOB step tests to avoid the onset of full-stick, bits designed with depth-of-cut control to reduce torsional oscillation, roller reamers to ensure stabilizer drag wasn't contributing to stickslip, and extension of bit gauge length to reduce the lateral movement of the bit in response to lateral force from the BHA.

Direct measurement, using high frequency downhole data, showed it is possible to achieve moderate reduction in bit dysfunction in hard laminated formations through these changes in practices and design. Greater gains might be expected with drillstrings having higher torsional stiffness than the 14,000 ft of 4 inch pipe used in these operations, or with less than the 5500ft of hard laminated formations. In other situations the gains would have been adequate to have enabled a bit to drill an entire interval without tripping. This work may have implications for operations in other unconventional plays, such as the Marcellus, Utica, Niobrara, Permian Basin, Haynesville, Tuscaloosa Marine Shale, and Granite Wash, where laminated formations, small hole sizes, and small diameter drillpipe are common.

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