The disclosure provides a solution for monitoring stick-slip vibrations without using any surface torque measurements. Instead, the disclosure provides a method to monitor stick-slip vibrations based on rotational speed. A stick-slip monitor, a top drive controller and a method of operating a drill string are provided herein that use rotational speed for monitoring stick-slip vibrations. In one example, the method of operating a drill string includes: (1) performing a frequency domain analysis of an RPM signal associated with a top drive that is used to rotate a drill string, and (2) determining a presence of torsional oscillations of the drill string based on the frequency domain analysis of the RPM signal.

The disclosure provides a solution for monitoring stick-slip vibrations without using any surface torque measurements. Instead, the disclosure provides a method to monitor stick-slip vibrations based on rotational speed. A stick-slip monitor, a top drive controller and a method of operating a drill string are provided herein that use rotational speed for monitoring stick-slip vibrations. In one example, the method of operating a drill string includes: (1) performing a frequency domain analysis of an RPM signal associated with a top drive that is used to rotate a drill string, and (2) determining a presence of torsional oscillations of the drill string based on the frequency domain analysis of the RPM signal.

Systems and methods for estimating a hardness of a rock mass during operation of an industrial machine. One system includes an electronic processor configured to receive a rock mass model and to receive live drilling data from the industrial machine. The electronic processor is also configured to update the rock mass model based on the live drilling data and to estimate a drilling index for a hole based on the updated rock mass model. After estimating a drilling index for the hole, the electronic processor is also configured to set a blasting parameter for the hole based on the estimated drilling index.

Systems and methods for estimating a hardness of a rock mass during operation of an industrial machine. One system includes an electronic processor configured to receive a rock mass model and to receive live drilling data from the industrial machine. The electronic processor is also configured to update the rock mass model based on the live drilling data and to estimate a drilling index for a hole based on the updated rock mass model. After estimating a drilling index for the hole, the electronic processor is also configured to set a blasting parameter for the hole based on the estimated drilling index.

Based on measurements of forces and rotational velocity experienced by a drill bit during drilling, drilling behavior is detected and identified. Measurements of forces on a drill bit including torque on bit (TOB), weight on bit (WOB), etc. and measurements of rotational velocity (rotations per minute or RPM) are acquired in real time at the drill bit. Various measurements are correlated to produce related combinations of measurements, such as WOB-RPM, TOB-RPM, and RPM-time. Based on fitting between the combinations of measurements and curves corresponding to predetermined torsional behavior trends, torsional, axial, and rotational behaviors are classified as functional or dysfunctional. A dysfunction identifier then identifies drill bit dysfunctions, such as high-frequency torsional noise, cutting-induced stick-slip, friction-inducted stick-slip, pipe-induced stick-slip, three-dimensional (3D) coupled vibrations (including subsets high-frequency torsional oscillations and low-frequency torsional oscillations), low-frequency torsional vibration, high-frequency torsional vibration, etc.) based on the functionality of the torsional, axial, and rotational behaviors. Based on drill bit dysfunction identification, dysfunctional drilling behavior can be mitigated.

Based on measurements of forces and rotational velocity experienced by a drill bit during drilling, drilling behavior is detected and identified. Measurements of forces on a drill bit including torque on bit (TOB), weight on bit (WOB), etc. and measurements of rotational velocity (rotations per minute or RPM) are acquired in real time at the drill bit. Various measurements are correlated to produce related combinations of measurements, such as WOB-RPM, TOB-RPM, and RPM-time. Based on fitting between the combinations of measurements and curves corresponding to predetermined torsional behavior trends, torsional, axial, and rotational behaviors are classified as functional or dysfunctional. A dysfunction identifier then identifies drill bit dysfunctions, such as high-frequency torsional noise, cutting-induced stick-slip, friction-inducted stick-slip, pipe-induced stick-slip, three-dimensional (3D) coupled vibrations (including subsets high-frequency torsional oscillations and low-frequency torsional oscillations), low-frequency torsional vibration, high-frequency torsional vibration, etc.) based on the functionality of the torsional, axial, and rotational behaviors. Based on drill bit dysfunction identification, dysfunctional drilling behavior can be mitigated.

A drilling control system may access a drilling plan for a borehole comprising one or more of planned path for the borehole, drill string information, mud properties, drill bit properties, formation properties, and drill rig properties. The system may receive a plurality of operating parameters from a rig for the borehole including one or more of an observed toolface, a spindle setting, a rate of penetration, a differential pressure, and a weight-on-bit. The system may receive one or more propagation functions for the borehole determined by a model of the drill string. The system may determine one or more spindle changes or block speed changes based at least in part on the propagation functions and the plurality of operating parameters. The system may generate one or more predicted drill properties from a simulator using the one or more spindle changes or the one or more block speed changes.

Systems and methods include a computer-implemented method for optimizing well drilling operations. An estimate for a maximum safe rate of penetration (ROP) is determined based on cutting concentrations in annulus (CCA) values. Hydraulics of mud pump+bit and jet impact force hydraulics are evaluated. A developed hole cleaning index is determined based on a carrying capacity model considering chemical and physical influences of drilling fluid rheology. A real-time Drilling Specific Energy (DSE) is determined using the estimate for the maximum safe ROP, the evaluated hydraulics, and the developed hole cleaning index. Optimal drilling parameters are determined using particle swarm optimization (PSO) and a penalty approach (PA). Optimal mechanical drilling parameters are determined using the optimal drilling parameters and by evaluating the real-time DSE. The optimal mechanical drilling parameters are used during drilling. The real-time developed DSE is correlated with fuel consumption to assess CO.sub.2 and toxics gases emission.

Systems and methods include a computer-implemented method for optimizing well drilling operations. An estimate for a maximum safe rate of penetration (ROP) is determined based on cutting concentrations in annulus (CCA) values. Hydraulics of mud pump+bit and jet impact force hydraulics are evaluated. A developed hole cleaning index is determined based on a carrying capacity model considering chemical and physical influences of drilling fluid rheology. A real-time Drilling Specific Energy (DSE) is determined using the estimate for the maximum safe ROP, the evaluated hydraulics, and the developed hole cleaning index. Optimal drilling parameters are determined using particle swarm optimization (PSO) and a penalty approach (PA). Optimal mechanical drilling parameters are determined using the optimal drilling parameters and by evaluating the real-time DSE. The optimal mechanical drilling parameters are used during drilling. The real-time developed DSE is correlated with fuel consumption to assess CO.sub.2 and toxics gases emission.

Systems and methods are disclosed for selecting a drill bit design that reduces or eliminates bit induced stick-slip. In some embodiments, each of a set of test drill bits is correlated with stick-slip events, wherein each of the test drill bits has a different design pattern comprising a combination of structural attributes. The design pattern stick-slip correlation includes, for each of the test drill bits, detecting variations in motion of the test drill bit during drilling operation. Stick-slip for each of the test drill bits is detected based on the detected variations in motion of the test drill bits during operation. The correlation further includes in response to detecting stick-slip, recording a stick-slip event in association with the corresponding test drill bit. The method further includes determining a performance efficiency value for each of the plurality of test drill bits and correlating the determined performance efficiency values with the stick-slip events to determine a threshold performance efficiency value. A design pattern for a drill bit is selecting or determined based, at least in part, on the threshold performance efficiency value.