Methods, apparatus, and products for receiving measurements indicative of present value torque (TrqPv) currently being applied by a top drive to a drill string extending in a well that penetrates a subterranean formation, and releasing torque accumulated in the drill string by determining polarity of TrqPv and, in response to a manual or automatic trigger, causing the top drive to perform an unwinding operation in a direction opposite to the determined TrqPv polarity.

Drilling system and methods may employ a weight-on-bit optimization for an existing drilling mode and, upon transitioning to a different drilling mode, determine an initial weight-on-bit within a range derived from: a sinusoidal buckling ratio, a helical buckling ratio, and the weight-on-bit value for the prior drilling mode. The sinusoidal buckling ratio is the ratio of a minimum weight-on-bit to induce sinusoidal buckling in a sliding mode to a minimum weight-on-bit to induce sinusoidal buckling in a rotating mode, and the helical buckling ratio is the ratio of a minimum weight-on-bit to induce helical buckling in the sliding mode to a minimum weight-on-bit to induce helical buckling in the rotating mode. The ratios are a function of the length of the drill string and hence vary with the position of the drill bit along the borehole.

Drilling system and methods may employ a weight-on-bit optimization for an existing drilling mode and, upon transitioning to a different drilling mode, determine an initial weight-on-bit within a range derived from: a sinusoidal buckling ratio, a helical buckling ratio, and the weight-on-bit value for the prior drilling mode. The sinusoidal buckling ratio is the ratio of a minimum weight-on-bit to induce sinusoidal buckling in a sliding mode to a minimum weight-on-bit to induce sinusoidal buckling in a rotating mode, and the helical buckling ratio is the ratio of a minimum weight-on-bit to induce helical buckling in the sliding mode to a minimum weight-on-bit to induce helical buckling in the rotating mode. The ratios are a function of the length of the drill string and hence vary with the position of the drill bit along the borehole.

Embodiments provide various systems and methods for using operating parameters of a drilling system for improving a drilling performance of the drilling system, including monitoring, determining, predicting, and/or controlling tool face orientation, tool face wagging, returning the spindle to a neutral position, and spindle reaction time. These systems and methods may be used together in combination with one or more of the others, or all together in one combination, or may be used separately, and may be combined with one or more other systems of a drilling rig, such as a bit guidance system, an autoslide system, and/or one or more autodrill systems.

Embodiments provide various systems and methods for using operating parameters of a drilling system for improving a drilling performance of the drilling system, including monitoring, determining, predicting, and/or controlling tool face orientation, tool face wagging, returning the spindle to a neutral position, and spindle reaction time. These systems and methods may be used together in combination with one or more of the others, or all together in one combination, or may be used separately, and may be combined with one or more other systems of a drilling rig, such as a bit guidance system, an autoslide system, and/or one or more autodrill systems.

A downhole ratchet is utilized between tubulars in the drill string to reduce torsion energy in the drill string. A first gear and a second gear are biased into engagement to drive the drill string below the position of the downhole ratchet in the drill string during normal drilling. The downhole ratchet is constructed to release between the first gear and second gear when the tubular below the ratchet spins faster than the tubular above the ratchet due to slip-stick. Once the tubular below spins more slowly or at the same speed then the ratchet mechanism locks the upper and lower tubulars together to rotate the bit. The effect is to release torsional energy in the drill string to reduce slip stick oscillations.

A downhole ratchet is utilized between tubulars in the drill string to reduce torsion energy in the drill string. A first gear and a second gear are biased into engagement to drive the drill string below the position of the downhole ratchet in the drill string during normal drilling. The downhole ratchet is constructed to release between the first gear and second gear when the tubular below the ratchet spins faster than the tubular above the ratchet due to slip-stick. Once the tubular below spins more slowly or at the same speed then the ratchet mechanism locks the upper and lower tubulars together to rotate the bit. The effect is to release torsional energy in the drill string to reduce slip stick oscillations.

In at least one embodiment, a control system may include a processor coupled to the database. The control system may include a memory accessible to the processor and storing instructions executable by the processor for: during slide drilling, detecting an increase to a first differential pressure (ΔP) that is greater than a first threshold pressure. In at least one embodiment, the control system may responsive to detecting the first ΔP, determining a time duration for which the first ΔP exceeds the first threshold pressure. In at least one embodiment, the control system may responsive to the first ΔP exceeding the first threshold pressure for less than a first threshold time, continuing the slide drilling without modifying a drilling parameter.

In at least one embodiment, a control system may include a processor coupled to the database. The control system may include a memory accessible to the processor and storing instructions executable by the processor for: during slide drilling, detecting an increase to a first differential pressure (ΔP) that is greater than a first threshold pressure. In at least one embodiment, the control system may responsive to detecting the first ΔP, determining a time duration for which the first ΔP exceeds the first threshold pressure. In at least one embodiment, the control system may responsive to the first ΔP exceeding the first threshold pressure for less than a first threshold time, continuing the slide drilling without modifying a drilling parameter.

A method comprises acquiring measurements of a force and a rotational velocity experienced by a drill bit while the drill bit is positioned in a wellbore; and identifying, by at least one processor, a type of dysfunction experienced by the drill bit based on a relationship of the measurement of the force and a measurement of the rotational velocity.