Quenching of Self-Excited Vibrations in Multi Degree-of-Freedom Systems: Application to Stick-Slip Mitigation in Drilling
Abstract: Surface-based damping mechanisms are the most commonly used method to mitigate stick-slip vibration in drilling systems, and their parameters are typically chosen based on low-order models of the drilling system. Field experience indicates that these low-order models do not capture all deformation mechanisms, and there is a need to include higher-order modes of deformation in the model. As a result, it is also imperative to delineate the effect of the surface damping mechanism on the higher-order modes of defo… Show more
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Cited by 3 publications
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North America shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for maximum rate of penetration (ROP). Downhole mud motor power sections have rapidly advanced to deliver more horsepower and torque, resulting in different downhole dynamics that have not been identified in the past. High-frequency (HF) compact drilling dynamics recorders embedded in the drill bit, mud-motor bit box, and motor top sub (sub-assembly) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. 3-axis shock, gyro and temperature sensors placed above and below the power section measure the dynamic response of power transfer to the bit and associated losses caused by back-drive dynamics. Detection of back-drive from surface measurements is not possible, and many measurement-while-drilling (MWD) systems do not have the measurement capability to identify the problem. Motor back-drive dynamics severity is dependent on many factors, including formation type, bit type, power section, WOB (weight on bit) and drill pipe size. The torsional energy stored and released in the drill string can be high due to the interaction between surface RPM (revolutions per minute)/torque output and mud-motor downhole RPM/torque. Torsional drill string energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration (ROP), rapid fatigue on downhole equipment, and motor or drillstring back-offs and twist-offs. A new mechanism of motor back-drive dynamics due to the use of an MWD pulser above a steerable motor is discovered. HF continuous gyro sensors and pressure sensors were deployed to capture the mechanism in which a positive mud pulser reduces as much as one third of the mud flow in the motor and bit rotation speed, creating a propensity for a bit to come to a complete stop in certain conditions and for the motor to rotate the drillstring backward. We have observed the backward rotation of a PDC drill bit during severe stick-slip and back-drive events (-50 RPM above the motor), confirming that the bit rotated backward for 9 mS every 133.3 mS (at 7.5Hz), using a 1000-Hz continuous sampling/recording in-bit gyro. In one field test, multiple drillstring dynamics recorders were used to measure the motor back-drive severity along the drillstring. It is discovered that the back-drive dynamics are worse at the drillstring, approximately 1110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring back-offs and twist-offs in a particular field. A motor back-drive mitigation tool was used in the field to compare the runs with and without the mitigation tool, while keeping the surface drilling parameters nearly the same. The downhole drilling dynamics sensors were used to confirm that the mitigation tool significantly reduced stick-slip and eliminated the motor back-drive dynamics in the same depth interval. Detailed analysis of the HF embedded downhole sensor data provides an in-depth understanding of mud-motor back-drive dynamics. The cause, severity, reduction in drilling performance and risk of incident can be identified, allowing performance and cost gains to be realized. This paper will detail the advantages to understanding and reducing motor back-drive dynamics, a topic that has not commonly been discussed in the past.
North America shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for maximum rate of penetration (ROP). Downhole mud motor power sections have rapidly advanced to deliver more horsepower and torque, resulting in different downhole dynamics that have not been identified in the past. High-frequency (HF) compact drilling dynamics recorders embedded in the drill bit, mud-motor bit box, and motor top sub (sub-assembly) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. 3-axis shock, gyro and temperature sensors placed above and below the power section measure the dynamic response of power transfer to the bit and associated losses caused by back-drive dynamics. Detection of back-drive from surface measurements is not possible, and many measurement-while-drilling (MWD) systems do not have the measurement capability to identify the problem. Motor back-drive dynamics severity is dependent on many factors, including formation type, bit type, power section, WOB (weight on bit) and drill pipe size. The torsional energy stored and released in the drill string can be high due to the interaction between surface RPM (revolutions per minute)/torque output and mud-motor downhole RPM/torque. Torsional drill string energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration (ROP), rapid fatigue on downhole equipment, and motor or drillstring back-offs and twist-offs. A new mechanism of motor back-drive dynamics due to the use of an MWD pulser above a steerable motor is discovered. HF continuous gyro sensors and pressure sensors were deployed to capture the mechanism in which a positive mud pulser reduces as much as one third of the mud flow in the motor and bit rotation speed, creating a propensity for a bit to come to a complete stop in certain conditions and for the motor to rotate the drillstring backward. We have observed the backward rotation of a PDC drill bit during severe stick-slip and back-drive events (-50 RPM above the motor), confirming that the bit rotated backward for 9 mS every 133.3 mS (at 7.5Hz), using a 1000-Hz continuous sampling/recording in-bit gyro. In one field test, multiple drillstring dynamics recorders were used to measure the motor back-drive severity along the drillstring. It is discovered that the back-drive dynamics are worse at the drillstring, approximately 1110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring back-offs and twist-offs in a particular field. A motor back-drive mitigation tool was used in the field to compare the runs with and without the mitigation tool, while keeping the surface drilling parameters nearly the same. The downhole drilling dynamics sensors were used to confirm that the mitigation tool significantly reduced stick-slip and eliminated the motor back-drive dynamics in the same depth interval. Detailed analysis of the HF embedded downhole sensor data provides an in-depth understanding of mud-motor back-drive dynamics. The cause, severity, reduction in drilling performance and risk of incident can be identified, allowing performance and cost gains to be realized. This paper will detail the advantages to understanding and reducing motor back-drive dynamics, a topic that has not commonly been discussed in the past.
Summary North American shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for the maximum rate of penetration (ROP). Downhole mud motor power sections have rapidly advanced to deliver more horsepower and torque, resulting in different downhole dynamics that have not been identified in the past. High-frequency (HF) compact drilling dynamics recorders embedded in the drill bit, mud motor bit box, and motor top subassembly (top-sub) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. Three-axis shock, gyro, and temperature sensors placed above and below the power section measure the dynamic response of power transfer to the bit and associated losses caused by back-drive dynamics. Detection of back-drive from surface measurements is not possible, and many measurement-while-drilling (MWD) systems do not have the measurement capability to identify the problem. Motor back-drive dynamics severity is dependent on many factors, including formation type, bit type, power section, weight on bit, and drillpipe size. The torsional energy stored and released in the drillstring can be high because of the interaction between surface rotation speed/torque output and mud motor downhole rotation speed/torque. Torsional drillstring energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration, rapid fatigue on downhole equipment, and motor or drillstring backoffs and twistoffs. A new mechanism of motor back-drive dynamics caused by the use of an MWD pulser above a steerable motor has been discovered. HF continuous gyro sensors and pressure sensors were deployed to capture the mechanism in which a positive mud pulser reduces as much as one-third of the mud flow in the motor and bit rotation speed, creating a propensity for a bit to come to a complete stop in certain conditions and for the motor to rotate the drillstring backward. We have observed the backward rotation of a polycrystalline diamond compact (PDC) drill bit during severe stick-slip and back-drive events (−50 rev/min above the motor), confirming that the bit rotated backward for 9 milliseconds (ms) every 133.3 ms (at 7.5 Hz), using a 1,000-Hz continuous sampling/recording in-bit gyro. In one field test, multiple drillstring dynamics recorders were used to measure the motor back-drive severity along the drillstring. It was discovered that the back-drive dynamics are worse at the drillstring, approximately 1,110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring backoffs and twistoffs in a particular field. A motor back-drive mitigation tool was used in the field to compare the runs with and without the mitigation tool while keeping the surface drilling parameters nearly the same. The downhole drilling dynamics sensors were used to confirm that the mitigation tool significantly reduced stick-slip and eliminated the motor back-drive dynamics in the same depth interval. Detailed analysis of the HF embedded downhole sensor data provides an in-depth understanding of mud motor back-drive dynamics. The cause, severity, reduction in drilling performance and risk of incident can be identified, allowing performance and cost gains to be realized. This paper will detail the advantages to understanding and reducing motor back-drive dynamics, a topic that has not commonly been discussed in the past.
This paper investigates the drill pipe twist-offs that occurred while drilling an S-shaped well in the 12 ¼" section. The presence of the 2nd mode shape of torsional vibration was observed and linked to the failure. Conditions that lead to a 2nd mode shape being triggered and sustained are discussed in addition to recommendations to prevent fatigue failures. 2nd mode shape torsional vibration is a standing wave with two nodes created along the drill string, with the first one being the top drive and 2nd located along the drill string. The drill pipe experiences the highest torque fluctuations in the rotational nodes during torsional vibration. A high-resolution drilling dynamics recorder was utilized to record a spectrum of torsional vibration frequencies, confirming the presence of the 2nd mode shape of torsional vibration. The multiple degrees of freedom spring-mass model was used to identify the node location, which was later compared to the locations of the actual twist-offs. The presence of the 2nd mode torsional vibration, its transition from the fundamental mode to the 2nd mode, and the conditions for the transition to happen were observed. Recommendations were developed on how to recognize the 2nd mode shape with the surface instrumentation, on the drill string design, and preventive inspection. Knowing the location of the node gives a possibility of selective inspection of the drill pipes once the 2nd mode shape was observed while drilling, minimizing the risk of fatigue failures. Also, the drill string design could be revised by increasing drill pipe strength within the nodes. The twist-off locations were found to match the calculated location of the node caused by the 2nd mode shape with a high degree of accuracy.
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