A system and method for calculating a path during drilling of a BHA between first and second survey points. The method includes calculating an amount of first incremental progress made by the BHA since the first survey point; calculating a first estimate of a first current location based on the first survey point and the amount of first incremental progress; causing at least one drilling parameter to be modified in order to alter a drilling direction of the BHA based on the first estimate; calculating an amount of second incremental progress made by the BHA; calculating a second estimate of the second current location based on the amount of second incremental progress and an aggregation of data received from the BHA, including data associated with the first survey point; and causing at least one drilling parameter to be modified in order to alter the drilling direction of the BHA.

A method for displaying performance of a wellbore drilling operation including wellbore cleaning includes defining drilling parameters for the drilling operation. The method includes defining a visualization tool including a boundary defined by the drilling parameters, where the boundary depicts an optimal rate of penetration (ROP). The method includes displaying the visualization tool with the optimal ROP, where the optimal ROP defines a maximum ROP for optimal wellbore cleaning based on the drilling parameters. The method includes displaying an actual rate of penetration (ROP) with respect to the optimal ROP on the visualization tool. The method further includes adjusting the actual ROP to match the optimal ROP.

A drilling system, assembly, and method may help optimize drilling in a system that involves more than one rotary tool that engages the formation. A rotary tool may be a rotary cutting tool, such as a drill bit or reamer, or some other rotary tool (e.g. stabilizer or rotary steerable tool) that has the potential to drag on the wall of the hole being drilled and take energy away from cutting. In an example, a wellbore or portion thereof is formed by rotating a first rotary cutting tool having a first cutting structure in engagement with one portion of the formation together with a second rotary cutting tool having a second cutting structure in engagement with another portion of the formation. Forces are obtained above and below the second cutting structure. One or more drilling parameter or drill bit design parameter are adjusted in relation to a force differential between the forces above and below the second cutting structure.

A drilling system, assembly, and method may help optimize drilling in a system that involves more than one rotary tool that engages the formation. A rotary tool may be a rotary cutting tool, such as a drill bit or reamer, or some other rotary tool (e.g. stabilizer or rotary steerable tool) that has the potential to drag on the wall of the hole being drilled and take energy away from cutting. In an example, a wellbore or portion thereof is formed by rotating a first rotary cutting tool having a first cutting structure in engagement with one portion of the formation together with a second rotary cutting tool having a second cutting structure in engagement with another portion of the formation. Forces are obtained above and below the second cutting structure. One or more drilling parameter or drill bit design parameter are adjusted in relation to a force differential between the forces above and below the second cutting structure.

A method for detecting net relative motion between a nuclear magnetic resonance (NMR) tool and a specimen includes disposing the NMR tool and the specimen in sensory range of one another, causing the NMR tool to make NMR measurements of the specimen, and processing the NMR measurements to detect net relative motion between the NMR tool and the specimen.

A method for detecting net relative motion between a nuclear magnetic resonance (NMR) tool and a specimen includes disposing the NMR tool and the specimen in sensory range of one another, causing the NMR tool to make NMR measurements of the specimen, and processing the NMR measurements to detect net relative motion between the NMR tool and the specimen.

Disclosed are methods, systems, and computer-readable medium to perform operations including: receiving real-time drilling data of a drilling operation of drilling a wellbore; using the drilling data to calculate at least one indicator of a tripping operation performed during the drilling operation; detecting, based on the least one indicator of the tripping operation, a drilling problem with the drilling operation; determining a corrective action to avoid or mitigate the drilling problem; and performing the corrective action to avoid or mitigate the drilling problem.

Disclosed are methods, systems, and computer-readable medium to perform operations including: receiving real-time drilling data of a drilling operation of drilling a wellbore; using the drilling data to calculate at least one indicator of a tripping operation performed during the drilling operation; detecting, based on the least one indicator of the tripping operation, a drilling problem with the drilling operation; determining a corrective action to avoid or mitigate the drilling problem; and performing the corrective action to avoid or mitigate the drilling problem.

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.