A proportional integral derivative (PID) controller implements control over a drilling system based on an integral term and a proportional term. The integral term is the integral of an operating drilling fluid pressure compared to a target drilling fluid pressure. The proportional term is the difference between an operating weight on bit and a target weight on bit. The sum of the proportional term and the integral term is multiplied by a controller parameter to determine a surface rate of penetration. A drill pipe lowering rate may be changed based on the determined surface rate of penetration, and the process may repeat in an iterative cycle until the integral term is reduced to an acceptable degree.

A proportional integral derivative (PID) controller implements control over a drilling system based on an integral term and a proportional term. The integral term is the integral of an operating drilling fluid pressure compared to a target drilling fluid pressure. The proportional term is the difference between an operating weight on bit and a target weight on bit. The sum of the proportional term and the integral term is multiplied by a controller parameter to determine a surface rate of penetration. A drill pipe lowering rate may be changed based on the determined surface rate of penetration, and the process may repeat in an iterative cycle until the integral term is reduced to an acceptable degree.

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.

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.

A method for using a mud motor may comprise drilling a borehole into a formation using a drill string connected to the mud motor and the mud motor is connected to a drill bit, measuring one or more parameters of the mud motor in the borehole, and sending the one or more parameters to surface. A system may comprise a mud motor connected to a drill string, a drill bit connected to the mud motor, a strain gauge, and in information handling system. The strain gauge may be connected to the drill bit and configured to take one or more parameters of the mud motor. The information handling system may be in communication with the strain gauge and configured to record the one or more parameters from the strain gauge.

A method for using a mud motor may comprise drilling a borehole into a formation using a drill string connected to the mud motor and the mud motor is connected to a drill bit, measuring one or more parameters of the mud motor in the borehole, and sending the one or more parameters to surface. A system may comprise a mud motor connected to a drill string, a drill bit connected to the mud motor, a strain gauge, and in information handling system. The strain gauge may be connected to the drill bit and configured to take one or more parameters of the mud motor. The information handling system may be in communication with the strain gauge and configured to record the one or more parameters from the strain gauge.

A drilling system includes a drill string, a plurality of sensors, and a computing system. The drill string includes a downhole motor. The sensors are coupled to the drill string. The computing system is coupled to the sensors. The computing system is configured to compute, based on measurements provided by the sensors, a motor stall index, and to determine, by comparing the motor stall index to a motor stall threshold, whether the downhole motor has stalled. The computing system is also configured to, responsive to a determination that the downhole motor has stalled, adjust operation of the drill string to restart the downhole motor.

A drilling system includes a drill string, a plurality of sensors, and a computing system. The drill string includes a downhole motor. The sensors are coupled to the drill string. The computing system is coupled to the sensors. The computing system is configured to compute, based on measurements provided by the sensors, a motor stall index, and to determine, by comparing the motor stall index to a motor stall threshold, whether the downhole motor has stalled. The computing system is also configured to, responsive to a determination that the downhole motor has stalled, adjust operation of the drill string to restart the downhole motor.