Abstract: A system and method that may include receiving information and analyzing the information with respect to tiered well construction activities. The system and method may also include determining at least one constraint associated with the tiered well construction activities based on the information. The system and method may additionally include generating a workflow that includes at least a series of tiered well construction activities based on the at least one constraint.

Abstract: A method for controlling field equipment can include receiving information via an interface of a control system; analyzing the information by the control system with respect to tiered well construction activities; based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.

Abstract: A method for controlling field equipment can include receiving information via an interface of a control system; analyzing the information by the control system with respect to tiered well construction activities; based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.

Abstract: A surface rig system includes components that consume power (e.g., using electrical motors). The power consumption of the components is monitored and used to infer other operational parameters. Illustratively, power consumption (e.g., current draw) of a shale shaker is monitored and used to infer: the volume of cuttings on the screen; changes in fluid viscosity, density, or rheology; health of the shaker screen; fluid cycle times; or screen clogging/blinding. Power consumption of pumps, fluid agitators, draw works, and other devices can also be monitored and used to infer parameters such as: fluid viscosity, density or rheology; hook load, or fluid slugging. Based on inferred parameters, changes may be made or advised for operation of equipment, including a shale shaker, downhole tool, pump, shaker screen, top drive, drilling fluid, or draw works.

Abstract: Computing systems, computer-readable media, and methods may include determining at least one automated sequence to be performed during a portion of a drilling operation by a drilling system. The at least one automated sequence may include performing one or more actions to cause a response in the drilling system. The method may include performing, during the drilling operation, the at least one automated sequence. Further, the method may include measuring, during the performance of the at least one automated sequence, one or more responses in the drilling system. The one or more responses may be measured within a wellbore undergoing the drilling operations and at a surface of the wellbore. The method may include modifying a model of the drilling system based at least in part of the one or more responses that were measured during the performance of the at least one automated sequence.

Abstract: A method for controlling field equipment can include receiving information via an interface of a control system; analyzing the information by the control system with respect to tiered well construction activities; based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.

Abstract: A method for drilling a well includes applying energy input to a drill string (31) by at least one of rotating the drill string (31) from surface and operating a drilling motor (41) disposed in the drill string (31) to operate a drill bit (2) at a bottom of the drill string (31); an amount of the applied energy not consumed in drilling formations caused by at least one of motion, deformation, and interaction of the drill string (31) is calculated; an amount of the applied energy used to drill formations below the drill bit (2) is calculated; and at least one drilling operating parameter is adjusted based on energy calculation before or during drilling operation.

Abstract: Computing systems, computer-readable media, and methods may include determining at least one automated sequence to be performed during a portion of a drilling operation by a drilling system. The at least one automated sequence may include performing one or more actions to cause a response in the drilling system. The method may include performing, during the drilling operation, the at least one automated sequence. Further, the method may include measuring, during the performance of the at least one automated sequence, one or more responses in the drilling system. The one or more responses may be measured within a wellbore undergoing the drilling operations and at a surface of the wellbore. The method may include modifying a model of the drilling system based at least in part of the one or more responses that were measured during the performance of the at least one automated sequence.

Abstract: A method for controlling field equipment can include receiving information via an interface of a control system; analyzing the information by the control system with respect to tiered well construction activities; based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.

Abstract: A calibration quality associated with a well-drilling apparatus can be determined. A projected value and a calculated value based upon a data set corresponding to a time interval section of a rig state of the well-drilling apparatus can be determined. A difference can be calculated between the projected value and the calculated value. A quality indicator can be applied to the difference, and a calibration quality based upon the application of the quality indicator can be determined.

Abstract: A method for drilling a well includes applying energy input to a drill string (31) by at least one of rotating the drill string (31) from surface and operating a drilling motor (41) disposed in the drill string (31) to operate a drill bit (2) at a bottom of the drill string (31); an amount of the applied energy not consumed in drilling formations caused by at least one of motion, deformation, and interaction of the drill string (31) is calculated; an amount of the applied energy used to drill formations below the drill bit (2) is calculated; and at least one drilling operating parameter is adjusted based on energy calculation before or during drilling operation.

Abstract: A method for transmitting data from a downhole tool to a surface location includes measuring a property in a wellbore using a downhole tool in the wellbore. A casing is positioned within the wellbore, and the downhole tool is positioned below at least a portion of the casing. A digital frame is generated using the downhole tool. The digital frame includes information corresponding to the property. The digital frame is encoded to superpose the information on a carrier signal. The carrier signal is converted to a voltage differential that is generated across an insulation layer in the downhole tool. The voltage differential causes a current to flow through a subterranean formation and into the casing above the downhole tool. A magnetic flux generated by the current flowing through the casing is detected using a sensor that is positioned at least partially within or at least partially around the casing.

Abstract: Computing systems, computer-readable media, and methods may include determining at least one automated sequence to be performed during a portion of a drilling operation by a drilling system. The at least one automated sequence may include performing one or more actions to cause a response in the drilling system. The method may include performing, during the drilling operation, the at least one automated sequence. Further, the method may include measuring, during the performance of the at least one automated sequence, one or more responses in the drilling system. The one or more responses may be measured within a wellbore undergoing the drilling operations and at a surface of the wellbore. The method may include modifying a model of the drilling system based at least in part of the one or more responses that were measured during the performance of the at least one automated sequence.

Abstract: A method for transmitting data from a downhole tool to a surface location includes measuring a property in a wellbore using a downhole tool in the wellbore. A casing is positioned within the wellbore, and the downhole tool is positioned below at least a portion of the casing. A digital frame is generated using the downhole tool. The digital frame includes information corresponding to the property. The digital frame is encoded to superpose the information on a carrier signal. The carrier signal is converted to a voltage differential that is generated across an insulation layer in the downhole tool. The voltage differential causes a current to flow through a subterranean formation and into the casing above the downhole tool. A magnetic flux generated by the current flowing through the casing is detected using a sensor that is positioned at least partially within or at least partially around the casing.

Abstract: A calibration quality associated with a well-drilling apparatus can be determined. A projected value and a calculated value based upon a data set corresponding to a time interval section of a rig state of the well-drilling apparatus can be determined. A difference can be calculated between the projected value and the calculated value. A quality indicator can be applied to the difference, and a calibration quality based upon the application of the quality indicator can be determined.